Enbridge (ENB) 10-K 14 Feb 20 2019 FY Annual report Financial data

Cover Page

Cover Page - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2019	Feb. 07, 2020	Jun. 30, 2019
Entity Listings [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	1-10934
Entity Registrant Name	ENBRIDGE INC
Entity Incorporation, State or Country Code	Z4
Entity Tax Identification Number	98-0377957
Entity Address, Address Line One	200, 425 - 1st Street S.W.
Entity Address, City or Town	Calgary
Entity Address, State or Province	AB
Entity Address, Country	CA
Entity Address, Postal Zip Code	T2P 3L8
City Area Code	403
Local Phone Number	231-3900
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 73.1
Entity Common Stock, Shares Outstanding		2,024,814,011
Documents Incorporated by Reference	Not applicable
Entity Central Index Key	0000895728
Document Fiscal Year Focus	2019
Amendment Flag	false
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Common Shares
Entity Listings [Line Items]
Title of 12(b) Security	Common Shares
Trading Symbol	ENB
Security Exchange Name	NYSE
6.375% Fixed-to-Floating Rate Subordinated Notes Series 2018-B due 2078
Entity Listings [Line Items]
Title of 12(b) Security	6.375% Fixed-to-Floating Rate Subordinated Notes Series 2018-B due 2078
Trading Symbol	ENBA
Security Exchange Name	NYSE

CONSOLIDATED STATEMENTS OF EARN

CONSOLIDATED STATEMENTS OF EARNINGS - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating revenues
Total operating revenues (Note 4)	$ 12,352	$ 11,598	$ 13,263	$ 12,856	$ 11,562	$ 11,345	$ 10,745	$ 12,726	$ 50,069	$ 46,378	$ 44,378
Operating expenses
Operating and administrative									6,991	6,792	6,442
Depreciation and amortization									3,391	3,246	3,163
Impairment of long-lived assets (Note 8 and Note 11)									423	1,104	4,463
Impairment of goodwill (Note 8 and Note 16)									0	1,019	102
Total operating expenses									41,809	41,562	42,807
Operating income	1,768	1,588	2,285	2,619	1,513	854	1,571	878	8,260	4,816	1,571
Income from equity investments (Note 13)									1,503	1,509	1,102
Other income/(expense)
Net foreign currency gain/(loss)									477	(522)	237
Gain/(loss) on dispositions									(300)	(46)	16
Other									258	516	199
Interest expense (Note 18)									(2,663)	(2,703)	(2,556)
Earnings before income taxes									7,535	3,570	569
Income tax recovery/(expense) (Note 25)									(1,708)	(237)	2,697
Earnings	914	1,060	1,830	2,023	1,283	213	1,327	510	5,827	3,333	3,266
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests									(122)	(451)	(407)
Earnings attributable to controlling interests	842	1,045	1,832	1,986	1,184	4	1,160	534	5,705	2,882	2,859
Preference share dividends									(383)	(367)	(330)
Earnings attributable to common shareholders	$ 746	$ 949	$ 1,736	$ 1,891	$ 1,089	$ (90)	$ 1,071	$ 445	$ 5,322	$ 2,515	$ 2,529
Earnings per common share attributable to common shareholders (in CAD per share)	$ 0.37	$ 0.47	$ 0.86	$ 0.94	$ 0.60	$ (0.05)	$ 0.63	$ 0.26	$ 2.64	$ 1.46	$ 1.66
Diluted earnings per common share attributable to common shareholders (in CAD per share)	$ 0.36	$ 0.47	$ 0.86	$ 0.94	$ 0.60	$ (0.05)	$ 0.63	$ 0.26	$ 2.63	$ 1.46	$ 1.65
Commodity sales
Operating revenues
Total operating revenues (Note 4)									$ 29,309	$ 27,660	$ 26,286
Operating expenses
Cost of goods and services sold									28,802	26,818	26,065
Gas distribution revenue
Operating revenues
Total operating revenues (Note 4)									4,205	4,360	4,215
Operating expenses
Cost of goods and services sold									2,202	2,583	2,572
Transportation and other services revenues
Operating revenues
Total operating revenues (Note 4)									$ 16,555	$ 14,358	$ 13,877

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Earnings	$ 5,827	$ 3,333	$ 3,266
Other comprehensive income/(loss), net of tax
Change in unrealized loss on cash flow hedges	(437)
Change in unrealized loss on cash flow hedges		(153)	(21)
Change in unrealized gain/(loss) on net investment hedges	281	(458)	490
Other comprehensive income/(loss) from equity investees	40	38	(27)
Reclassification to earnings of loss on cash flow hedges	127
Reclassification to earnings of loss on cash flow hedges		152	313
Reclassification to earnings of pension and other postretirement benefits amounts	13	12	19
Actuarial gain/(loss) on pension plans and other postretirement benefits	(96)	(52)	8
Foreign currency translation adjustments	(3,035)	4,599	(3,060)
Other comprehensive income/(loss), net of tax	(3,107)	4,138	(2,278)
Comprehensive income	2,720	7,471	988
Comprehensive income attributable to noncontrolling interests and redeemable noncontrolling interests	(7)	(801)	(160)
Comprehensive income attributable to controlling interests	2,713	6,670	828
Preference share dividends	(383)	(367)	(330)
Comprehensive income attributable to common shareholders	$ 2,330	$ 6,303	$ 498

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - CAD ($) $ in Millions	Total	Preference shares	Common Shares	Additional paid-in capital	Retained earnings/(deficit)	Accumulated other comprehensive income/(loss)	Reciprocal shareholding	Total Enbridge Inc. shareholders' equity	Noncontrolling Interest	Merger TransactionCommon Shares
Balance at Dec. 31, 2016		$ 7,255	$ 10,492	$ 3,399	$ (716)	$ 1,058	$ (102)		$ 577
Increase (Decrease) in Stockholders' Equity
Shares issued		492	1,500
Common shares issued in Merger Transaction			0							$ 37,429
Dividend Reinvestment and Share Purchase Plan			1,226
Exercise of stock options			90	(95)
Stock-based compensation				82
Sponsored Vehicles buy-in				0
Repurchase of noncontrolling interest				0					8,955
Dilution gain on Spectra Energy Partners, LP restructuring (Note 20)				0
Change in reciprocal interest				0
Other				(192)
Sale of noncontrolling interests in subsidiaries				0					0
Earnings attributable to controlling interests	$ 2,859				2,859
Preference share dividends					(330)
Common share dividends declared					(4,702)
Dividends paid to reciprocal shareholder					30
Redemption value adjustment to redeemable noncontrolling interests (Note 20)	(292)				292				0
Other					99	0
Impact of Sponsored Vehicles buy-in						0
Other comprehensive income/(loss) attributable to common shareholders, net of tax						(2,031)
Change in reciprocal interest							0
Earnings attributable to noncontrolling interests									232
Change in unrealized gain/(loss) on cash flow hedges									15
Foreign currency translation adjustments									(431)
Reclassification to earnings of loss on cash flow hedges									139
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax									(277)
Comprehensive income/(loss) attributable to noncontrolling interests									(45)
Enbridge Energy Company, Inc. common control transaction									(343)
Distributions									(839)
Contributions									832
Deconsolidation of Sabal Trail Transmission, LLC									(2,318)
Spectra Energy Partners, LP restructuring (Note 20)									0
Change in noncontrolling interests on Sponsored Vehicles buy-in									0
Repurchase of noncontrolling interest	0								0
Dilution gain and other									778
Balance at Dec. 31, 2017	$ 65,732	7,747	50,737	3,194	(2,468)	(973)	(102)	$ 58,135	7,597
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share (in CAD per share)	$ 2.41
Modified retrospective adoption of ASC 606 Revenue from Contracts with Customers	$ 0				0
Shares issued		0	0
Common shares issued in Merger Transaction			12,727							0
Dividend Reinvestment and Share Purchase Plan			1,181
Exercise of stock options			32	(24)
Stock-based compensation				49
Sponsored Vehicles buy-in				(4,323)
Repurchase of noncontrolling interest				0					0
Dilution gain on Spectra Energy Partners, LP restructuring (Note 20)				1,136
Change in reciprocal interest				47
Other				(158)
Sale of noncontrolling interests in subsidiaries				79					1,183
Earnings attributable to controlling interests	2,882				2,882
Preference share dividends					(367)
Common share dividends declared					(5,019)
Dividends paid to reciprocal shareholder					33
Redemption value adjustment to redeemable noncontrolling interests (Note 20)	456				(456)				(210)
Other					(57)	0
Impact of Sponsored Vehicles buy-in						(142)
Other comprehensive income/(loss) attributable to common shareholders, net of tax						3,787
Change in reciprocal interest							14
Earnings attributable to noncontrolling interests									334
Change in unrealized gain/(loss) on cash flow hedges									31
Foreign currency translation adjustments									294
Reclassification to earnings of loss on cash flow hedges									4
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax									329
Comprehensive income/(loss) attributable to noncontrolling interests									663
Enbridge Energy Company, Inc. common control transaction									0
Distributions									(857)
Contributions									24
Deconsolidation of Sabal Trail Transmission, LLC									0
Spectra Energy Partners, LP restructuring (Note 20)									(1,486)
Change in noncontrolling interests on Sponsored Vehicles buy-in									(2,867)
Repurchase of noncontrolling interest	(4,469)								0
Dilution gain and other									(82)
Balance at Dec. 31, 2018	$ 73,435	7,747	64,677	0	(5,538)	2,672	(88)	69,470	3,965
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share (in CAD per share)	$ 2.68
Modified retrospective adoption of ASC 606 Revenue from Contracts with Customers	$ (38)				(86)
Shares issued		0	0
Common shares issued in Merger Transaction			0							$ 0
Dividend Reinvestment and Share Purchase Plan			0
Exercise of stock options			69	(61)
Stock-based compensation				34
Sponsored Vehicles buy-in				0
Repurchase of noncontrolling interest				65					0
Dilution gain on Spectra Energy Partners, LP restructuring (Note 20)				0
Change in reciprocal interest				117
Other				32
Sale of noncontrolling interests in subsidiaries				0					0
Earnings attributable to controlling interests	5,705				5,705
Preference share dividends					(383)
Common share dividends declared					(6,125)
Dividends paid to reciprocal shareholder					18
Redemption value adjustment to redeemable noncontrolling interests (Note 20)					0				(300)
Other					9	48
Impact of Sponsored Vehicles buy-in						0
Other comprehensive income/(loss) attributable to common shareholders, net of tax						(2,992)
Change in reciprocal interest							37
Earnings attributable to noncontrolling interests									122
Change in unrealized gain/(loss) on cash flow hedges									(7)
Foreign currency translation adjustments									(108)
Reclassification to earnings of loss on cash flow hedges									0
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax									(115)
Comprehensive income/(loss) attributable to noncontrolling interests									7
Enbridge Energy Company, Inc. common control transaction									0
Distributions									(254)
Contributions									12
Deconsolidation of Sabal Trail Transmission, LLC									0
Spectra Energy Partners, LP restructuring (Note 20)									0
Change in noncontrolling interests on Sponsored Vehicles buy-in									0
Repurchase of noncontrolling interest									(65)
Dilution gain and other									(1)
Balance at Dec. 31, 2019	$ 69,407	$ 7,747	$ 64,746	$ 187	(6,314)	$ (272)	$ (51)	$ 66,043	$ 3,364
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share (in CAD per share)	$ 2.95
Modified retrospective adoption of ASC 606 Revenue from Contracts with Customers					$ 0

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating activities
Earnings	$ 5,827	$ 3,333	$ 3,266
Depreciation and amortization	3,391	3,246	3,163
Deferred income tax (recovery)/expense	1,156	(148)	(2,877)
Changes in unrealized (gain)/loss on derivative instruments, net (Note 24)	(1,751)	903	(1,242)
Earnings from equity investments	(1,503)	(1,509)	(1,102)
Distributions from equity investments	1,804	1,539	1,264
Impairment of long-lived assets	423	1,104	4,463
Impairment of goodwill	0	1,019	102
(Gain)/loss on dispositions	254	8	(120)
Other	56	92	79
Changes in operating assets and liabilities	(259)	915	(338)
Net cash provided by operating activities	9,398	10,502	6,658
Investing activities
Capital expenditures	(5,492)	(6,806)	(8,287)
Long-term investments and restricted long-term investments	(1,159)	(1,312)	(3,586)
Distributions from equity investments in excess of cumulative earnings	417	1,277	125
Additions to intangible assets	(200)	(540)	(789)
Cash acquired in Merger Transaction	0	0	682
Proceeds from dispositions	2,110	4,452	628
Other	(20)	(12)	212
Affiliate loans, net	(314)	(76)	(22)
Net cash used in investing activities	(4,658)	(3,017)	(11,037)
Financing activities
Net change in short-term borrowings	(127)	(420)	721
Net change in commercial paper and credit facility draws	825	(2,256)	(1,249)
Debenture and term note issues, net of issue costs	6,176	3,537	9,483
Debenture and term note repayments	(4,668)	(4,445)	(5,054)
Sale of noncontrolling interest in subsidiary	0	1,289	0
Purchase of interest in consolidated subsidiary	0	0	(227)
Contributions from noncontrolling interests	12	24	832
Distributions to noncontrolling interests	(254)	(857)	(919)
Contributions from redeemable noncontrolling interests	0	70	1,178
Distributions to redeemable noncontrolling interests	0	(325)	(247)
Sponsored Vehicle buy-in cash payment	0	(64)	0
Preference shares issued	0	0	489
Redemption of preferred shares	(300)	(210)	0
Common shares issued	18	21	1,549
Preference share dividends	(383)	(364)	(330)
Common share dividends	(5,973)	(3,480)	(2,750)
Other	(71)	(23)	0
Net cash (used in)/provided by financing activities	(4,745)	(7,503)	3,476
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	44	68	(72)
Net increase/(decrease) in cash and cash equivalents and restricted cash	39	50	(975)
Cash and cash equivalents and restricted cash at beginning of year	637	587	1,562
Cash and cash equivalents and restricted cash at end of year	676	637	587
Supplementary cash flow information
Cash paid for income taxes	571	277	172
Cash paid for interest, net of amount capitalized	2,738	2,508	2,668
Property, plant and equipment non-cash accruals	$ 730	$ 847	$ 889

CONSOLIDATED STATEMENTS OF FINA

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents	$ 648	$ 518
Restricted cash	28	119
Accounts receivable and other	6,781	6,517
Accounts receivable from affiliates	69	79
Inventory	1,299	1,339
Total Current assets	8,825	8,572
Property, plant and equipment, net	93,723	94,540
Long-term investments	16,528	16,707
Restricted long-term investments	434	323
Deferred amounts and other assets	7,433	8,558
Intangible assets, net	2,173	2,372
Goodwill	33,153	34,459
Total deferred income tax assets	1,000	1,374
Total assets	163,269	166,905
Current liabilities
Short-term borrowings	898	1,024
Accounts payable and other	10,063	9,863
Accounts payable to affiliates	21	40
Interest payable	624	669
Current portion of long-term debt	4,404	3,259
Total Current liabilities	16,010	14,855
Long-term debt	59,661	60,327
Other long-term liabilities	8,324	8,834
Deferred income taxes	9,867	9,454
Total Liabilities	93,862	93,470
Commitments and contingencies
Share capital
Preference shares	7,747	7,747
Common shares (1,695 and 943 outstanding at December 31, 2017 and December 31,2016, respectively)	64,746	64,677
Additional paid-in capital	187	0
Deficit	(6,314)	(5,538)
Accumulated other comprehensive income/(loss)	(272)	2,672
Reciprocal shareholding	(51)	(88)
Total Enbridge Inc. shareholders’ equity	66,043	69,470
Noncontrolling interests	3,364	3,965
Total Equity	69,407	73,435
Total liabilities and equity	$ 163,269	$ 166,905

CONSOLIDATED STATEMENTS OF FI_2

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Parenthetical) - shares shares in Millions	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Common shares, outstanding (in shares)	2,025	2,022

BUSINESS OVERVIEW

BUSINESS OVERVIEW	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
BUSINESS OVERVIEW	BUSINESS OVERVIEW The terms “we,” “our,” “us” and “Enbridge” as used in this report refer collectively to Enbridge Inc. and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Enbridge. Enbridge is a publicly traded energy transportation and distribution company. We conduct our business through five business segments: Liquids Pipelines; Gas Transmission and Midstream; Gas Distribution and Storage; Renewable Power Generation; and Energy Services. These reporting segments are strategic business units established by senior management to facilitate the achievement of our long-term objectives, to aid in resource allocation decisions and to assess operational performance. LIQUIDS PIPELINES Liquids Pipelines consists of pipelines and related terminals in Canada and the United States that transport various grades of crude oil and other liquid hydrocarbons, including the Mainline System, Regional Oil Sands System, Gulf Coast and Mid-Continent, Southern Lights Pipeline, Express-Platte System, Bakken System, and Feeder Pipelines and Other. GAS TRANSMISSION AND MIDSTREAM Gas Transmission and Midstream consists of investments in natural gas pipelines and gathering and processing facilities in Canada and the United States, including US Gas Transmission, Canadian Gas Transmission, US Midstream and Other. GAS DISTRIBUTION AND STORAGE Gas Distribution and Storage consists of our natural gas utility operations, the core of which is Enbridge Gas, which serves residential, commercial and industrial customers, located throughout Ontario. Gas Distribution and Storage also includes natural gas distribution activities in Quebec and an investment in Noverco, which holds a majority interest in a subsidiary entity engaged in distribution and energy transportation primarily in Quebec. RENEWABLE POWER GENERATION Renewable Power Generation consists primarily of investments in wind and solar power generating assets, as well as geothermal, waste heat recovery, and transmission assets. In North America, assets are primarily located in the provinces of Alberta, Saskatchewan, Ontario, and Quebec and in the states of Colorado, Texas, Indiana and West Virginia. We also have offshore wind assets in operation and under development located in United Kingdom, Germany, and France. ENERGY SERVICES The Energy Services businesses in Canada and the United States undertake physical commodity marketing activity and logistical services to manage our volume commitments on various pipeline systems. Energy Services also provides energy marketing services to North American refiners, producers and other customers. ELIMINATIONS AND OTHER In addition to the segments noted above, Eliminations and Other includes operating and administrative costs and the impact of foreign exchange hedge settlements, which are not allocated to business segments. Eliminations and Other also includes new business development activities and corporate investments. SPONSORED VEHICLES BUY-IN In the fourth quarter of 2018, Enbridge completed the buy-ins of our sponsored vehicles: SEP, EEP, Enbridge Energy Management, L.L.C. (EEM) and ENF, (referred to herein collectively as the Sponsored Vehicles) in a series of combination transactions, through which we acquired all of the outstanding equity securities of the Sponsored Vehicles not beneficially owned by us (collectively, the Sponsored Vehicles buy-in). Please refer to Note 20 - Noncontrolling Interests for further discussion of the transactions. ACQUISITION OF SPECTRA ENERGY CORP On February 27, 2017, Enbridge and Spectra Energy Corp (Spectra Energy) combined in a stock-for-stock merger transaction for a purchase price of $37.5 billion . Under the terms of the Merger Transaction, Spectra Energy shareholders received 0.984 shares of Enbridge common stock for each share of Spectra Energy common stock that they owned, resulting in us acquiring 100% ownership of Spectra Energy. Please refer to Note 8 - Acquisitions and Dispositions for further discussion of the transaction. DISPOSITIONS During the years ended December 31, 2019 and 2018, we have disposed of a number of our non-core assets. Please refer to Note 8 - Acquisitions and Dispositions for further discussion of these transactions.

SIGNIFICANT ACCOUNTING POLICIES

SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
SIGNIFICANT ACCOUNTING POLICIES	SIGNIFICANT ACCOUNTING POLICIES These consolidated financial statements are prepared in accordance with U.S. Generally accepted accounting principles in the United States of America (U.S. GAAP) . Amounts are stated in Canadian dollars unless otherwise noted. As a SEC registrant, we are permitted to use U.S. GAAP for purposes of meeting both our Canadian and United States continuous disclosure requirements. BASIS OF PRESENTATION AND USE OF ESTIMATES The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities in the consolidated financial statements. Significant estimates and assumptions used in the preparation of the consolidated financial statements include, but are not limited to: carrying values of regulatory assets and liabilities (Note 7) ; purchase price allocations (Note 8) ; unbilled revenues; depreciation rates and carrying value of property, plant and equipment (Note 11) ; amortization rates of intangible assets (Note 15) ; measurement of goodwill (Note 16) ; fair value of ARO (Note 19) ; valuation of stock-based compensation (Note 22) ; fair value of financial instruments (Note 24) ; provisions for income taxes (Note 25) ; assumptions used to measure retirement and other postretirement benefit obligations (OPEB) (Note 26) ; commitments and contingencies (Note 30) ; and estimates of losses related to environmental remediation obligations (Note 30) . Actual results could differ from these estimates. PRINCIPLES OF CONSOLIDATION The consolidated financial statements include our accounts and accounts of our subsidiaries and VIEs for which we are the primary beneficiary. A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains and losses of the entity. Upon inception of a contractual agreement, we perform an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a VIE. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE entity that could potentially be significant to the VIE. Where we conclude that we are the primary beneficiary of a VIE, we consolidate the accounts of that VIE. We assess all variable interests in the entity and use our judgment when determining if we are the primary beneficiary. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. We assess the primary beneficiary determination for a VIE on an ongoing basis, if there are changes in the facts and circumstances related to a VIE. The consolidated financial statements also include the accounts of any limited partnerships where we represent the general partner and, based on all facts and circumstances, control such limited partnerships, unless the limited partner has substantive participating rights or substantive kick-out rights. For certain investments where we retain an undivided interest in assets and liabilities, we record our proportionate share of assets, liabilities, revenues and expenses. If an entity is determined to not be a VIE, the voting interest entity model is applied, where an investor holding the majority voting rights consolidates the entity. All significant intercompany accounts and transactions are eliminated upon consolidation. Ownership interests in subsidiaries represented by other parties that do not control the entity are presented in the consolidated financial statements as activities and balances attributable to noncontrolling interests and redeemable noncontrolling interests. Investments and entities over which we exercise significant influence are accounted for using the equity method. REGULATION Certain parts of our businesses are subject to regulation by various authorities including, but not limited to, the CER, the FERC, the Alberta Energy Regulator, the OEB and La Régie de l’Energie du Québec. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under U.S. GAAP for non rate-regulated entities. Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates or expected to be paid to cover future abandonment costs in relation to the CER’s LMCI. Long-term regulatory assets are recorded in Deferred amounts and other assets and current regulatory assets are recorded in Accounts receivable and other. Long-term regulatory liabilities are included in Other long-term liabilities and current regulatory liabilities are recorded in Accounts payable and other. Regulatory assets are assessed for impairment if we identify an event indicative of possible impairment. The recognition of regulatory assets and liabilities is based on the actions, or expected future actions, of the regulator. To the extent that the regulator’s actions differ from our expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, we would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. A regulatory asset or liability is recognized in respect of deferred income taxes when it is expected the amounts will be recovered or settled through future regulator-approved rates. Allowance for funds used during construction (AFUDC) is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component, which are both capitalized based on rates set out in a regulatory agreement. The corresponding impact on earnings is included in Interest expense for the interest component and Other income for the equity component. In the absence of rate regulation, we would capitalize interest using a capitalization rate based on our cost of borrowing, whereas the capitalized equity component, the corresponding earnings during the construction phase and the subsequent depreciation relating to the equity component would not be recognized. For certain regulated operations to which U.S. GAAP guidance for phase-in plans applies, negotiated depreciation rates recovered in transportation tolls may be less than the depreciation expense calculated in accordance with U.S. GAAP in early years of long-term contracts but recovered in future periods when tolls exceed depreciation. Depreciation expense on such assets is recorded in accordance with U.S. GAAP and no deferred regulatory asset is recorded (Note 7) . REVENUE RECOGNITION For businesses that are not rate-regulated, revenues are recorded when products have been delivered or services have been performed, the amount of revenue can be reliably measured and collectability is reasonably assured. Customer credit worthiness is assessed prior to agreement signing, as well as throughout the contract duration. Certain revenues from liquids and gas pipeline businesses are recognized under the terms of committed delivery contracts rather than the cash tolls received. Long-term take-or-pay contracts, under which shippers are obligated to pay fixed amounts rateably over the contract period regardless of volumes shipped, may contain make-up rights. Make-up rights are earned by shippers when minimum volume commitments are not utilized during the period but under certain circumstances can be used to offset overages in future periods, subject to expiry periods. We recognize revenues associated with make-up rights at the earlier of when the make-up volume is shipped, the make-up right expires or when it is determined that the likelihood that the shipper will utilize the make-up right is remote. Certain offshore pipeline transportation contracts require Enbridge to provide transportation services for the life of the underlying producing fields. Under these arrangements, shippers pay Enbridge a fixed monthly toll for a defined period of time which may be shorter than the estimated reserve life of the underlying producing fields, resulting in a contract period which extends past the period of cash collection. Fixed monthly toll revenues are recognized ratably over the committed volume made available to shippers throughout the contract period, regardless of when cash is received. For the years ended December 31, 2019 , 2018 and 2017 , cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements was $169 million , $208 million , and $196 million , respectively. For rate-regulated businesses, revenues are recognized in a manner that is consistent with the underlying agreements as approved by the regulators. Natural gas utilities revenues are recorded on the basis of regular meter readings and estimates of customer usage from the last meter reading to the end of the reporting period. Estimates are based on historical consumption patterns and heating degree days experienced. Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in our distribution franchise area. Since July 1, 2011, Canadian Mainline (excluding Lines 8 and 9) earnings are governed by the CTS, under which revenues are recorded when services are performed. Effective on that date, we prospectively discontinued the application of rate-regulated accounting for those assets with the exception of flow-through income taxes covered by specific rate orders. Our Energy Services segment enters into commodity purchase and sale arrangements that are recorded gross because the related contracts are not held for trading purposes and we are acting as the principal in the transactions. For our energy marketing contracts, an estimate of revenues and commodity costs for the month of December is included in the Consolidated Statements of Earnings for each year based on the best available volume and price data for the commodity delivered and received. DERIVATIVE INSTRUMENTS AND HEDGING Non-qualifying Derivatives Non-qualifying derivative instruments are used primarily to economically hedge foreign exchange, interest rate and commodity price earnings exposure. Non-qualifying derivatives are measured at fair value with changes in fair value recognized in earnings in Transportation and other services revenues, Commodity costs, Operating and administrative expense, Other income/(expense) and Interest expense. Derivatives in Qualifying Hedging Relationships We use derivative financial instruments to manage our exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to our share price. Hedge accounting is optional and requires Enbridge to document the hedging relationship and test the hedging item’s effectiveness in offsetting changes in fair values or cash flows of the underlying hedged item on an ongoing basis. We present the earnings effects of hedging items with the hedged transaction. Derivatives in qualifying hedging relationships are categorized as cash flow hedges, fair value hedges or net investment hedges. Cash Flow Hedges We use cash flow hedges to manage our exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to our share price. The change in the fair value of a cash flow hedging instrument is recorded in OCI and is reclassified to earnings when the hedged item impacts earnings. If a derivative instrument designated as a cash flow hedge ceases to be effective or is terminated, hedge accounting is discontinued and the gain or loss at that date is deferred in OCI and recognized in earnings concurrently with the related transaction. If an anticipated hedged transaction is no longer probable, the gain or loss is recognized immediately in earnings. Subsequent gains and losses from derivative instruments for which hedge accounting has been discontinued are recognized in earnings in the period in which they occur. Fair Value Hedges We may use fair value hedges to hedge the fair value of debt instruments. The change in the fair value of the hedging instrument is recorded in earnings with changes in the fair value of the hedged risk of the asset or liability that is designated as part of the hedging relationship. If a fair value hedge is discontinued or ceases to be effective, the hedged risk of the asset or liability ceases to be remeasured at fair value and the cumulative fair value adjustment to the carrying value of the hedged item is recognized in earnings over the remaining life of the hedged item. Net Investment Hedges Gains and losses arising from translation of net investment in foreign operations from their functional currencies to Enbridge’s Canadian dollar presentation currency are included in cumulative translation adjustments (CTA), a component of OCI. We designate foreign currency derivatives and United States dollar denominated debt as hedges of net investments in United States dollar denominated foreign operations. As a result, the change in the fair value of the foreign currency derivatives as well as the translation of United States dollar denominated debt are reflected in OCI. Amounts recognized previously in Accumulated other comprehensive income/(loss) (AOCI) are reclassified to earnings when there is a reduction of the hedged net investment resulting from disposal of a foreign operation. Classification of Derivatives We recognize the fair market value of derivative instruments on the Consolidated Statements of Financial Position as current and non-current assets or liabilities depending on the timing of the settlements and the resulting cash flows associated with the instruments. Fair value amounts related to cash flows occurring beyond one year are classified as non-current. Cash inflows and outflows related to derivative instruments are classified as Operating activities on the Consolidated Statements of Cash Flows. Balance Sheet Offset Assets and liabilities arising from derivative instruments may be offset in the Consolidated Statements of Financial Position when we have the legal right and intention to settle them on a net basis. Transaction Costs Transaction costs are incremental costs directly related to the acquisition of a financial asset or the issuance of a financial liability. We incur transaction costs primarily from the issuance of debt and account for these costs as a deduction from Long-term debt on the Statements of Financial Position. These costs are amortized using the effective interest rate method over the term of the related debt instrument and are recorded in Interest expense. EQUITY INVESTMENTS Equity investments over which we exercise significant influence, but do not have controlling financial interests, are accounted for using the equity method. Equity investments are initially measured at cost and are adjusted for our proportionate share of undistributed equity earnings or loss. Equity investments are increased for contributions made to and decreased for distributions received from the investees. To the extent an equity investee undertakes activities necessary to commence its planned principal operations, we capitalize interest costs associated with the investment during such period. RESTRICTED LONG-TERM INVESTMENTS Long-term investments that are restricted as to withdrawal or usage, for the purposes of the CER’s LMCI, are presented as Restricted long-term investments on the Consolidated Statements of Financial Position. OTHER INVESTMENTS Generally, we classify equity investments in entities over which we do not exercise significant influence and that do not have readily determinable fair values as other investments measured at fair value measurement alternative and recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for an identical or similar investment of the same issuer. Investments in equity securities measured using the fair value measurement alternative are reviewed for impairment each reporting period. Equity investments with readily determinable fair values are measured at fair value through net income. Dividends received from investments in equity securities are recognized in earnings when the right to receive payment is established. Investments in debt securities are classified either as available for sale securities measured at fair value through OCI or as held to maturity securities measured at amortized cost. NONCONTROLLING INTERESTS Noncontrolling interests represent ownership interests attributable to third parties in certain consolidated subsidiaries. The portion of equity not owned by us in such entities is reflected as Noncontrolling interests within the equity section of the Consolidated Statements of Financial Position. INCOME TAXES Income taxes are accounted for using the liability method. Deferred income tax assets and liabilities are recorded based on temporary differences between the tax bases of assets and liabilities and their carrying values for accounting purposes. Deferred income tax assets and liabilities are measured using the tax rate that is expected to apply when the temporary differences reverse. For our regulated operations, a deferred income tax liability or asset is recognized with a corresponding regulatory asset or liability, respectively, to the extent taxes can be recovered through rates. Any interest and/or penalty incurred related to tax is reflected in income taxes. FOREIGN CURRENCY TRANSACTIONS AND TRANSLATION Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which Enbridge or a reporting subsidiary operates, referred to as the functional currency. Transactions denominated in foreign currencies are translated into the functional currency using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the rate of exchange in effect at the balance sheet date. Exchange gains and losses resulting from translation of monetary assets and liabilities are included in the Consolidated Statements of Earnings in the period in which they arise. Gains and losses arising from translation of foreign operations’ functional currencies to our Canadian dollar presentation currency are included in the CTA component of AOCI and are recognized in earnings upon sale of the foreign operation. Asset and liability accounts are translated at the exchange rates in effect on the balance sheet date, while revenues and expenses are translated using monthly average exchange rates. CASH AND CASH EQUIVALENTS Cash and cash equivalents include short-term investments with a term to maturity of three months or less when purchased. RESTRICTED CASH Cash and cash equivalents that are restricted as to withdrawal or usage, in accordance with specific commercial arrangements, are presented as Restricted cash on the Consolidated Statements of Financial Position. LOANS AND RECEIVABLES Affiliate long-term notes receivable are measured at amortized cost using the effective interest rate method, net of any impairment losses recognized. Accounts receivable and other are measured at cost. ALLOWANCE FOR DOUBTFUL ACCOUNTS Allowance for doubtful accounts is determined based on collection history. When we have determined that further collection efforts are unlikely to be successful, amounts charged to the allowance for doubtful accounts are applied against the impaired accounts receivable. NATURAL GAS IMBALANCES The Consolidated Statements of Financial Position include in-kind balances as a result of differences in gas volumes received and delivered for customers. Since settlement of certain imbalances is in-kind, changes in the balances do not have an effect on our Consolidated Statements of Earnings or Consolidated Statements of Cash Flows. Most natural gas volumes owed to or by us are valued at natural gas market index prices as at the balance sheet dates. INVENTORY Inventory is comprised of natural gas in storage held in Enbridge Gas, and crude oil and natural gas held primarily by energy services businesses in the Energy Services segment. Natural gas in storage in Enbridge Gas is recorded at the quarterly prices approved by the OEB in the determination of distribution rates. The actual price of gas purchased may differ from the OEB approved price. The difference between the approved price and the actual cost of the gas purchased is deferred as a liability for future refund or as an asset for collection as approved by the OEB. Other commodities inventory is recorded at the lower of cost, as determined on a weighted average basis, or market value. Upon disposition, other commodities inventory is recorded to Commodity costs on the Consolidated Statements of Earnings at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is recorded at historical cost. Expenditures for construction, expansion, major renewals and betterments are capitalized. Maintenance and repair costs are expensed as incurred. Expenditures for project development are capitalized if they are expected to have future benefit. We capitalize interest incurred during construction for non-rate-regulated assets. For rate-regulated assets, AFUDC is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component. Two primary methods of depreciation are utilized. For distinct assets, depreciation is generally provided on a straight-line basis over the estimated useful lives of the assets commencing when the asset is placed in service. For largely homogeneous groups of assets with comparable useful lives, the pool method of accounting for property, plant and equipment is followed whereby similar assets are grouped and depreciated as a pool. When group assets are retired or otherwise disposed of, gains and losses are generally not reflected in earnings but are booked as an adjustment to accumulated depreciation. DEFERRED AMOUNTS AND OTHER ASSETS Deferred amounts and other assets primarily include costs which regulatory authorities have permitted, or are expected to permit, to be recovered through future rates including: deferred income taxes; contractual receivables under the terms of long-term delivery contracts; derivative financial instruments; and actuarial gains and losses arising from defined benefit pension plans. INTANGIBLE ASSETS Intangible assets consist primarily of certain software costs, customer relationships and emission allowances. We capitalize costs incurred during the application development stage of internal use software projects . Customer relationships represent the underlying relationship from long-term agreements with customers that are capitalized upon acquisition. From January 1, 2017 through July 3, 2018, emission allowances, which are recorded at their original cost, were purchased in order to meet GHG compliance obligations. Intangible assets are generally amortized on a straight-line basis over their expected lives, commencing when the asset is available for use, with the exception of emission allowances, which are not amortized as they will be used to satisfy compliance obligations as they come due. GOODWILL Goodwill represents the excess of the purchase price over the fair value of net identifiable assets on acquisition of a business. The carrying value of goodwill, which is not amortized, is assessed for impairment annually, or more frequently if events or changes in circumstances arise that suggest the carrying value of goodwill may be impaired. We perform our annual review of the goodwill balance on April 1. We perform our annual review for impairment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. We have the option to first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment test. When performing a qualitative assessment, we determine the drivers of fair value for each reporting unit and evaluate whether those drivers have been positively or negatively affected by relevant events and circumstances since the last fair value assessment. Our evaluation includes, but is not limited to, assessment of macroeconomic trends, regulatory environments, capital accessibility, operating income trends, and industry conditions. Based on our assessment of the qualitative factors, if we determine it is more likely than not that the fair value of the reporting unit is less than it's carrying amount, a quantitative goodwill impairment test is performed. The quantitative goodwill impairment test involves determining the fair value of our reporting units and comparing those values to the carrying value of each reporting unit. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value. This amount should not exceed the carrying amount of goodwill. Fair value of our reporting units is estimated using a combination of discounted cash flow model and earnings multiples techniques. The determination of fair value using the discounted cash flow model technique requires the use of estimates and assumptions related to discount rates, projected operating income, terminal value growth rates, capital expenditures and working capital levels. The cash flow projections included significant judgments and assumptions relating to revenue growth rates and expected future capital expenditure. The determination of fair value using the earnings multiples technique requires assumptions to be made in relation to maintainable earnings and earnings multipliers for reporting units. The allocation of goodwill to held for sale and disposed businesses is based on the relative fair value of businesses included in the particular reporting unit. IMPAIRMENT We review the carrying values of our long-lived assets as events or changes in circumstances warrant. If it is determined that the carrying value of an asset exceeds the undiscounted cash flows expected from the asset, we calculate fair value based on the discounted cash flows and write the assets down to the extent that the carrying value exceeds the fair value. With respect to investments in debt securities and equity investments, we assess at each balance sheet date whether there is objective evidence that a financial asset is impaired by completing a quantitative or qualitative analysis of factors impacting the investment. If there is objective evidence of impairment, we value the expected discounted cash flows using observable market inputs and determine whether the decline below carrying value is other than temporary. If the decline is determined to be other than temporary, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the asset. With respect to other financial assets, we assess the assets for impairment when there is no longer reasonable assurance of timely collection. If evidence of impairment is noted, we reduce the value of the financial asset to its estimated realizable amount, determined using discounted expected future cash flows. ASSET RETIREMENT OBLIGATIONS ARO associated with the retirement of long-lived assets are measured at fair value and recognized as Accounts payable and other or Other long-term liabilities in the period in which they can be reasonably determined. The fair value approximates the cost a third party would charge to perform the tasks necessary to retire such assets and is recognized at the present value of expected future cash flows. ARO are added to the carrying value of the associated asset and depreciated over the asset’s useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. Our estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements. PENSION AND OTHER POSTRETIREMENT BENEFITS We sponsor defined benefit and defined contribution pension plans, and defined benefit OPEB plans, which provide group health care, life insurance benefits and other postretirement benefits. Defined benefit pension obligation and net periodic benefit cost are estimated using the projected unit credit method, which incorporates management’s best estimates of future salary levels, other cost escalations, retirement ages of employees and other actuarial factors including discount rates and mortality. The OPEB benefit obligation and net periodic benefit cost are estimated using the projected unit credit method, where benefits are attributed to years of service, taking into consideration projection of benefit costs. We use mortality tables issued by the Society of Actuaries in the United States (revised in 2019) and the Canadian Institute of Actuaries (revised in 2014 ) to measure the benefit obligations of our United States pension plan (the United States Plan) and our Canadian pension plans (the Canadian Plans), respectively. We determine discount rates by reference to rates of high-quality long-term corporate bonds with maturities that approximate the timing of future payments we anticipate making under each of the respective plans. Funded pension and OPEB plan assets are measured at fair value. The expected return on funded pension and OPEB plan assets is determined using market related values and assumptions on the invested asset mix consistent with the investment policies relating to the plan assets. The market related values reflect estimated return on investments consistent with long-term historical averages for similar assets. Actuarial gains and losses arise from the difference between the actual and expected rate of return on plan assets for that period (funded pension and OPEB plans) or from changes in actuarial assumptions used to determine the accrued benefit obligation, including discount rate, changes in headcount and salary inflation experience. The excess of the fair value of a plan’s assets over the fair value of a plan’s benefit obligation is recognized as Deferred amounts and other assets in our Consolidated Statements of Financial Position. The excess of the fair value of a plan’s benefit obligation over the fair value of a plan’s assets is recognized as Accounts payable and other and Other long-term liabilities in our Consolidated Statements of Financial Position. Net periodic benefit cost is charged to Earnings and includes: • Cost of benefits provided in exchange for employee services rendered during the year (current service cost); • Interest cost of plan obligations; • Expected return on plan assets (funded pension and OPEB plans); • Amortization of prior service costs on a straight-line basis over the expected average remaining service period of the active employee group covered by the plans; and • Amortization of

CHANGES IN ACCOUNTING POLICIES

CHANGES IN ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2019
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
CHANGES IN ACCOUNTING POLICIES	CHANGES IN ACCOUNTING POLICIES CHANGES IN ACCOUNTING POLICIES There were no changes in accounting policies during the year ended December 31, 2019. ADOPTION OF NEW ACCOUNTING STANDARDS Cloud Computing Arrangements Effective January 1, 2019, we adopted Accounting Standards Update (ASU) 2018-15 on a prospective basis. The new standard was issued to provide guidance on the accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. This ASU specifies that an entity would apply ASC 350-40, Internal-use software, to determine which implementation costs related to a hosting arrangement that is a service contract should be capitalized and which should be expensed. The amendments in the update also require that the capitalized costs be amortized on a straight-line basis generally over the term of the arrangement and presented in the same income statement line as fees paid for the hosting service, in addition to specifying that the capitalized costs must be presented on the same balance sheet line as the prepayment of fees related to the hosting arrangement. This ASU requires similar consistency in classifications from a cash flow statement perspective. The adoption of this ASU did not have a material impact on our consolidated financial statements. Improvements to Accounting for Hedging Activities Effective January 1, 2019, we adopted ASU 2017-12 on a modified retrospective basis. The new standard was issued with the objective of better aligning a company’s risk management activities and the resulting hedge accounting reflected in the financial statements. The amendments allow cash flow hedging of contractually specified components in financial and non-financial items. As a result of the new standard, hedge ineffectiveness will no longer be measured or recorded, and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The adoption of this accounting update did not have a material impact on our consolidated financial statements. Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium Effective January 1, 2019, we adopted ASU 2017-08 on a modified retrospective basis. The new standard was issued with the intent of shortening the amortization period to the earliest call date for certain callable debt securities held at a premium. The adoption of this accounting update did not have a material impact on our consolidated financial statements. Recognition of Leases Effective January 1, 2019 we adopted ASU 2016-02 Leases (Topic 842) using the modified retrospective approach. We recognize an arrangement as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We recognize right-of-use (ROU) assets and the related lease liabilities on the statement of financial position for operating lease arrangements with a term of 12 months or longer. We do not separate non-lease components from the associated lease components of our lessee contracts and account for both components as a single lease component. We combine lease and non-lease components within a contract for operating lessor leases when certain conditions are met. ROU assets are assessed for impairment using the same approach as is applied for other long-lived assets, as described under the Impairment section of the Significant Accounting Policies Note 2 in the annual consolidated financial statements. Lease liabilities and ROU assets require the use of judgment and estimates, which are applied in determining the term of a lease, appropriate discount rates, whether an arrangement contains a lease, whether there are any indicators of impairment for ROU assets and whether any ROU assets should be grouped with other long-lived assets for impairment testing. In adopting Topic 842, we elected the package of practical expedients permitted under the transition guidance. The election to apply the package of practical expedients allows an entity to not apply the new lease standard to the prior year comparative periods in the year of adoption. The application of the package of practical expedients also permits entities not to reassess whether any expired or existing contracts contain leases in accordance with the new guidance, lease classifications, and whether initial direct costs capitalized under current guidance continue to meet the definition of initial direct costs under the new guidance. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements that had commenced prior to January 1, 2019. On January 1, 2019, ROU assets and corresponding lease liabilities of $771 million were recorded in connection with the adoption of Topic 842. When added to the $85 million of pre-existing liabilities relating to operating leases for which we no longer utilize the leased assets, total lease liabilities at January 1, 2019 were $856 million . All lease liabilities were measured using a weighted average discount rate of 4.32% . The adoption of this standard had no impact to the Consolidated Statements of Earnings, Comprehensive Income, Changes in Equity or Cash Flows during the period. Improvements to Related Party Guidance for Variable Interest Entities Effective September 30, 2019, we adopted ASU 2018-17 on a retrospective basis. The new standard was issued with the objective to improve the related party guidance on determining whether fees paid to decision makers and service providers (decision maker fees) are variable interests. Under the new guidance, reporting entities must consider indirect interests held through related parties in common control arrangements on a proportionate basis, rather than as the equivalent of a direct interest in its entirety, when determining if decision maker fees constitute a variable interest. The adoption of this ASU did not have a material impact on our consolidated financial statements. FUTURE ACCOUNTING POLICY CHANGES Accounting for Income Taxes ASU 2019-12 was issued in December 2019 with the intent of simplifying the accounting for income taxes. The accounting update removes certain exceptions to the general principles in ASC 740 as well as provides simplification by clarifying and amending existing guidance. ASU 2019-12 is effective January 1, 2021 and entities are permitted to adopt the standard early. We are currently assessing the impact of the new standard on our consolidated financial statements. Clarifying Interaction between Collaborative Arrangements and Revenue from Contracts with Customers ASU 2018-18 was issued in November 2018 to provide clarity on when transactions between entities in a collaborative arrangement should be accounted for under the new revenue standard, ASC 606. In determining whether transactions in collaborative arrangements should be accounted under the revenue standard, the update specifies that entities shall apply unit of account guidance to identify distinct goods or services and whether such goods and services are separately identifiable from other promises in the contract. ASU 2018-18 also precludes entities from presenting transactions with a collaborative partner which are not in scope of the new revenue standard together with revenue from contracts with customers. The accounting update is effective January 1, 2020 and early adoption is permitted. The adoption of ASU 2018-18 is not expected to have a material impact on our consolidated financial statements. Disclosure Effectiveness In August 2018, the Financial Accounting Standards Board issued two amendments as a part of its disclosure framework project aimed to improve the effectiveness of disclosures in the notes to financial statements. ASU 2018-14 was issued in August 2018 to improve disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The amendment modifies the current guidance by adding and removing several disclosure requirements while also clarifying the guidance on current disclosure requirements. ASU 2018-14 is effective January 1, 2021 and entities are permitted to adopt the standard early. The adoption of ASU 2018-14 is not expected to have a material impact on our consolidated financial statements. ASU 2018-13 was issued to improve the disclosure requirements for fair value measurements by eliminating and modifying some disclosures, while also adding new disclosures. This update is effective January 1, 2020, however entities are permitted to early adopt the eliminated or modified disclosures. The adoption of ASU 2018-13 is not expected to have a material impact on our consolidated financial statements. Accounting for Credit Losses ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delay the recognition until it is probable a loss has been incurred. The accounting update adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity will recognize as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. Further, ASU 2018-19 was issued in November 2018 to clarify that operating lease receivables should be accounted for under the new leases standard, ASC 842, and are not within the scope of ASC 326, Financial Instruments - Credit Losses. Both accounting updates are effective January 1, 2020. We have performed a detailed evaluation as of December 31, 2019 and do not anticipate the adoption of ASU 2016-13 to have a material impact on our consolidated financial statements.

REVENUE

REVENUE	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
REVENUE	REVENUE REVENUE FROM CONTRACTS WITH CUSTOMERS Major Products and Services Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated Year ended December 31, 2019 (millions of Canadian dollars) Transportation revenue 9,082 4,477 743 — — — 14,302 Storage and other revenue 109 268 201 — — — 578 Gas gathering and processing revenue — 423 — — — — 423 Gas distribution revenue — — 4,210 — — — 4,210 Electricity and transmission revenue — — — 180 — — 180 Commodity sales — 4 — — — — 4 Total revenue from contracts with customers 9,191 5,172 5,154 180 — — 19,697 Commodity sales — — — — 29,305 — 29,305 Other revenue 1,2 659 30 9 387 (2 ) (16 ) 1,067 Intersegment revenue 369 5 16 — 71 (461 ) — Total revenue 10,219 5,207 5,179 567 29,374 (477 ) 50,069 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated Year ended December 31, 2018 (millions of Canadian dollars) Transportation revenue 8,488 3,928 875 — — — 13,291 Storage and other revenue 101 222 196 — — — 519 Gas gathering and processing revenue — 815 — — — — 815 Gas distribution revenue — — 4,376 — — — 4,376 Electricity and transmission revenue — — — 206 — — 206 Commodity sales — 1,590 — — — — 1,590 Total revenue from contracts with customers 8,589 6,555 5,447 206 — — 20,797 Commodity sales — — — — 26,070 — 26,070 Other revenue 1,2 (894 ) 6 9 361 4 25 (489 ) Intersegment revenue 384 10 14 — 154 (562 ) — Total revenue 8,079 6,571 5,470 567 26,228 (537 ) 46,378 1 Includes mark-to-market gains/(losses) from our hedging program. 2 Includes revenues from lease contracts. Refer to Note 27 Leases. We disaggregate revenue into categories which represent our principal performance obligations within each business segment because these revenue categories represent the most significant revenue streams in each segment and consequently are considered to be the most relevant revenue information for management to consider in evaluating performance. Contract Balances Contract Receivables Contract Assets Contract Liabilities (millions of Canadian dollars) Balance as at December 31, 2018 1,929 191 1,297 Balance as at December 31, 2019 2,099 216 1,424 Contract receivables represent the amount of receivables derived from contracts with customers. Contract assets represent the amount of revenue which has been recognized in advance of payments received for performance obligations we have fulfilled (or partially fulfilled) and prior to the point in time at which our right to the payment is unconditional. Amounts included in contract assets are transferred to accounts receivable when our right to the consideration becomes unconditional. Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenue. Revenue recognized during the year ended December 31, 2019 included in contract liabilities at the beginning of the period is $185 million . Increases in contract liabilities from cash received, net of amounts recognized as revenue during the year ended December 31, 2019 were $358 million . Revenue recognized during the year ended December 31, 2018 included in contract liabilities at the beginning of the period is $183 million . Increases in contract liabilities from cash received, net of amounts recognized as revenue during the year ended December 31, 2018 were $449 million . Performance Obligations Segment Nature of Performance Obligation Liquids Pipelines • Transportation and storage of crude oil and NGLs Gas Transmission and Midstream • Transportation, storage, gathering, compression and treating of natural gas • Transportation of NGLs • Sale of crude oil, natural gas and NGLs Gas Distribution and Storage • Supply and delivery of natural gas • Transportation of natural gas • Storage of natural gas Renewable Power Generation • Generation and transmission of electricity • Delivery of electricity from renewable energy generation facilities There was no material revenue recognized in the year ended December 31, 2019 from performance obligations satisfied in previous periods. Payment Terms Payments are received monthly from customers under long-term transportation, commodity sales, and gas gathering and processing contracts. Payments from Gas Distribution and Storage customers are received on a continuous basis based on established billing cycles. Certain contracts in the United States offshore business provide for us to receive a series of fixed monthly payments (FMPs) for a specified period which is less than the period during which the performance obligations are satisfied. As a result, a portion of the FMPs is recorded as a contract liability. The FMPs are not considered to be a financing arrangement because the payments are scheduled to match the production profiles of offshore oil and gas fields, which generate greater revenue in the initial years of their productive lives. Revenue to be Recognized from Unfulfilled Performance Obligations Total revenue from performance obligations expected to be fulfilled in future periods is $ 65.8 billion , of which $ 7.1 billion is expected to be recognized during the year ended December 31, 2020 . The revenues excluded from the amounts above based on optional exemptions available under ASC 606, as explained below, represent a significant portion of our overall revenues and revenues from contracts with customers. Certain revenues such as flow-through operating costs charged to shippers are recognized at the amount for which we have the right to invoice our customers and are excluded from the amounts of revenue to be recognized in the future from unfulfilled performance obligations above. Variable consideration is excluded from the amounts above due to the uncertainty of the associated consideration, which is generally resolved when actual volumes and prices are determined. For example, we consider interruptible transportation service revenues to be variable revenues since volumes cannot be estimated. Additionally, the effect of escalation on certain tolls which are contractually escalated for inflation has not been reflected in the amounts above as it is not possible to reliably estimate future inflation rates. Revenues for periods extending beyond the current rate settlement term for regulated contracts where the tolls are periodically reset by the regulator are excluded from the amounts above since future tolls remain unknown. Finally, revenues from contracts with customers which have an original expected duration of one year or less are excluded from the amounts above. SIGNIFICANT JUDGMENTS MADE IN RECOGNIZING REVENUE Long-Term Transportation Agreements For long-term transportation agreements, significant judgments pertain to the period over which revenue is recognized and whether the agreement provides for make-up rights for the shippers. Transportation revenue earned from firm contracted capacity arrangements is recognized ratably over the contract period. Transportation revenue from interruptible or volumetric-based arrangements is recognized when services are performed. Estimates of Variable Consideration Revenue from arrangements subject to variable consideration is recognized only to the extent that it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is subsequently resolved. Uncertainties associated with variable consideration relate principally to differences between estimated and actual volumes and prices. These uncertainties are resolved each month when actual volumes are sold or transported and actual tolls and prices are determined. Recognition and Measurement of Revenue Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Consolidated Year ended December 31, 2019 (millions of Canadian dollars) Revenue from products transferred at a point in time — 4 65 — — 69 Revenue from products and services transferred over time 1 9,191 5,168 5,089 180 — 19,628 Total revenue from contracts with customers 9,191 5,172 5,154 180 — 19,697 1 Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural gas distribution, natural gas storage services and electricity sales. Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Consolidated Year ended December 31, 2018 (millions of Canadian dollars) Revenue from products transferred at a point in time 1 — 1,590 68 — — 1,658 Revenue from products and services transferred over time 2 8,589 4,965 5,379 206 — 19,139 Total revenue from contracts with customers 8,589 6,555 5,447 206 — 20,797 1 Revenue from sales of crude oil, natural gas and NGLs. Revenue from commodity sales where the commodity sold is not immediately consumed prior to use is recognized at the point in time when the contractually specified volume of the commodity has been delivered. 2 Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural gas distribution, natural gas storage services and electricity sales. Performance Obligations Satisfied Over Time For arrangements involving the transportation and sale of petroleum products and natural gas where the transportation services or commodities are simultaneously received and consumed by the shipper or customer, we recognize revenue over time using an output method based on volumes of commodities delivered or transported. The measurement of the volumes transported or delivered corresponds directly to the benefits received by the shippers or customers during that period. Determination of Transaction Prices Prices for gas processing and transportation services are determined based on the capital cost of the facilities, pipelines and associated infrastructure required to provide such services plus a rate of return on capital invested that is determined either through negotiations with customers or through regulatory processes for those operations that are subject to rate regulation. Prices for commodities sold are determined by reference to market price indices plus or minus a negotiated differential and in certain cases a marketing fee. Prices for natural gas sold and distribution services provided by regulated natural gas distribution operations are prescribed by regulation.

SEGMENTED INFORMATION

SEGMENTED INFORMATION	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
SEGMENTED INFORMATION	SEGMENTED INFORMATION Segmented information for the years ended December 31, 2019 , 2018 and 2017 is as follows: Year ended December 31, 2019 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues 10,219 5,207 5,179 567 29,374 (477 ) 50,069 Commodity and gas distribution costs (29 ) — (2,354 ) (2 ) (29,091 ) 472 (31,004 ) Operating and administrative (3,298 ) (2,232 ) (1,149 ) (189 ) (44 ) (79 ) (6,991 ) Impairment of long-lived assets (21 ) (105 ) — (297 ) — — (423 ) Income/(loss) from equity investments 780 682 4 31 8 (2 ) 1,503 Other income/(expense) 30 (181 ) 67 1 3 515 435 Earnings before interest, income tax expense, and depreciation and amortization 7,681 3,371 1,747 111 250 429 13,589 Depreciation and amortization (3,391 ) Interest expense (2,663 ) Income tax expense (1,708 ) Earnings 5,827 Capital expenditures 1 2,548 1,753 1,100 23 2 124 5,550 Total property, plant and equipment, net 48,783 25,268 15,622 3,658 24 368 93,723 Year ended December 31, 2018 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues 8,079 6,571 5,470 567 26,228 (537 ) 46,378 Commodity and gas distribution costs (16 ) (1,481 ) (2,748 ) (7 ) (25,689 ) 540 (29,401 ) Operating and administrative (3,124 ) (2,102 ) (1,111 ) (157 ) (73 ) (225 ) (6,792 ) Impairment of long-lived assets (180 ) (914 ) — (4 ) — (6 ) (1,104 ) Impairment of goodwill — (1,019 ) — — — — (1,019 ) Income/(loss) from equity investments 577 930 11 (28 ) 18 1 1,509 Other income/(expense) (5 ) 349 89 (2 ) (2 ) (481 ) (52 ) Earnings/(loss) before interest, income tax expense, and depreciation and amortization 5,331 2,334 1,711 369 482 (708 ) 9,519 Depreciation and amortization (3,246 ) Interest expense (2,703 ) Income tax expense (237 ) Earnings 3,333 Capital expenditures 1 3,102 2,644 1,066 33 — 27 6,872 Total property, plant and equipment, net 49,214 25,601 15,148 4,335 22 220 94,540 Year ended December 31, 2017 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues 8,913 7,067 4,992 534 23,282 (410 ) 44,378 Commodity and gas distribution costs (18 ) (2,834 ) (2,689 ) — (23,508 ) 412 (28,637 ) Operating and administrative (2,949 ) (1,756 ) (960 ) (163 ) (47 ) (567 ) (6,442 ) Impairment of long-lived assets — (4,463 ) — — — — (4,463 ) Impairment of goodwill — (102 ) — — — — (102 ) Income/(loss) from equity investments 416 653 23 6 8 (4 ) 1,102 Other income/(expense) 33 166 24 (5 ) 2 232 452 Earnings/(loss) before interest, income tax expense, and depreciation and amortization 6,395 (1,269 ) 1,390 372 (263 ) (337 ) 6,288 Depreciation and amortization (3,163 ) Interest expense (2,556 ) Income tax recovery 2,697 Earnings 3,266 Capital expenditures 1 2,799 4,016 1,177 321 1 108 8,422 1 Includes allowance for equity funds used during construction. The measurement basis for preparation of segmented information is consistent with the significant accounting policies (Note 2) . No non-affiliated customer exceeds 10% of our third-party revenues for the years ended December 31, 2019 and 2018 , respectively. Our largest non-affiliated customer accounted for approximately 11.8% of our third-party revenues for the year ended December 31, 2017 . Revenue from this one customer is primarily reported in the Energy Services segment. GEOGRAPHIC INFORMATION Revenues 1 Year ended December 31, 2019 2018 2017 (millions of Canadian dollars) Canada 19,954 19,023 18,076 United States 30,115 27,355 26,302 50,069 46,378 44,378 1 Revenues are based on the country of origin of the product or service sold. Property, Plant and Equipment 1 December 31, 2019 2018 (millions of Canadian dollars) Canada 45,993 44,716 United States 47,730 49,824 93,723 94,540 1 Amounts are based on the location where the assets are held.

EARNINGS PER COMMON SHARE

EARNINGS PER COMMON SHARE	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
EARNINGS PER COMMON SHARE	EARNINGS PER COMMON SHARE BASIC Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding. The weighted average number of common shares outstanding has been reduced by our pro-rata weighted average interest in our own common shares of approximately 6 million as at December 31, 2019 , 12 million as at December 31, 2018 , and 13 million as at December 31, 2017 , resulting from our reciprocal investment in Noverco. DILUTED The treasury stock method is used to determine the dilutive impact of stock options. This method assumes any proceeds from the exercise of stock options would be used to purchase common shares at the average market price during the period. Weighted average shares outstanding used to calculate basic and diluted earnings per share are as follows: December 31, 2019 2018 2017 (number of shares in millions) Weighted average shares outstanding 2,017 1,724 1,525 Effect of dilutive options 3 3 7 Diluted weighted average shares outstanding 2,020 1,727 1,532 For the years ended December 31, 2019 , 2018 and 2017 , 17.8 million , 26.8 million and 14.3 million , respectively, of anti-dilutive stock options with a weighted average exercise price of $53.56 , $50.38 and $56.71 , respectively, were excluded from the diluted earnings per common share calculation.

REGULATORY MATTERS

REGULATORY MATTERS	12 Months Ended
	Dec. 31, 2019
Regulated Operations [Abstract]
REGULATORY MATTERS	REGULATORY MATTERS GENERAL INFORMATION ON RATE REGULATION AND ITS ECONOMIC EFFECTS We record assets and liabilities that result from regulated ratemaking processes that would not be recorded under GAAP for non-regulated entities. See Note 2 - Significant Accounting Policies for further discussion. A number of our businesses are subject to regulation by various regulators, including the CER, OEB and FERC. We also collect and set aside funds to cover future pipeline abandonment costs for all CER regulated pipelines as a result of the CER's regulatory requirements under LMCI (Note 14) and to cover future removal and site restoration reserves as approved by the OEB and other agencies. Amounts expected to be paid for these future costs are recognized as long-term regulatory liabilities. Our significant regulated businesses and the related accounting impacts, are described below. Liquids Pipelines Canadian Mainline Canadian Mainline includes the Canadian portion of the mainline system and is subject to regulation by the CER. Tolls (excluding Lines 8 and 9) are currently governed by the 10 -year CTS, which establishes a CLT for all volumes shipped on the Canadian Mainline and an IJT for all volumes shipped from western Canadian receipt points to delivery points on Enbridge’s Lakehead System, as well as delivery points on the Canadian Mainline downstream of the Lakehead System. The CTS was negotiated with shippers in accordance with CER guidelines, was approved by the CER in June 2011, and took effect July 1, 2011. Under the CTS, a regulatory asset is recognized to offset deferred income taxes as a CER rate order governing flow-through income tax treatment permits future recovery. No other material regulatory assets or liabilities are recognized under the terms of the CTS. Southern Lights Pipeline The United States portion of the Southern Lights Pipeline is regulated by the FERC and the Canadian portion of the Southern Lights Pipeline is regulated by the CER. Shippers on the Southern Lights Pipeline are subject to long-term transportation contracts under a cost-of-service toll methodology. Toll adjustments are filed annually with the regulators and provide for the recovery of allowable operating and debt financing costs, plus a pre-determined after-tax rate of return on equity of 10% . Gas Transmission and Midstream BC Pipeline and BC Field Services Until December 31, 2019, our Gas Transmission and Midstream business in British Columbia was comprised of BC Pipeline and BC Field Services. BC Pipeline and BC Field Services provide fee-for-service based natural gas transmission and raw gas gathering and processing services, respectively. BC Pipeline is regulated by the CER under full cost-of-service regulation. Under the current CER-authorized rate structure for our BC Pipeline, income tax costs are recovered in tolls based on the current income tax payable and do not include accruals for deferred income tax. However, as income taxes become payable as a result of the reversal of the temporary differences that created the deferred income taxes, it is expected that tolls will be adjusted to recover these taxes. Since most existing temporary differences are related to property, plant and equipment costs, this recovery is expected to occur over the life of the BC Pipeline assets. On December 31, 2019, we closed the sale of our BC Field Services business to Brookfield Infrastructure Partners L.P. and its institutional partners (Brookfield) (Note 8) . The BC Field Services business was regulated by the CER under the Framework for Light-Handed Regulation. Regulatory assets of $349 million , related to the regulatory offset to deferred income tax liabilities associated with the BC Field Services business, were derecognized as a result of this sale. Spectra Energy Partners, LP Most of SEP's gas transmission and storage services are regulated by the FERC and may also be subject to the jurisdiction of various other federal, state and local agencies. Rates for the FERC jurisdictional services are governed by the applicable FERC-approved natural gas tariffs while rates for the intrastate and/or gathering services are governed by the appropriate state gas commissions. Gas Distribution and Storage Enbridge Gas Inc. Enbridge Gas' distribution rates, beginning in 2019, are set under a five-year IR framework using a price cap mechanism. The price cap mechanism establishes new rates each year through an annual base rate escalation at inflation less a 0.3% productivity factor, annual updates for certain costs to be passed through to customers, and where applicable, the recovery of material discrete incremental capital investments beyond those that can be funded through base rates. The IR framework includes the continuation and establishment of certain deferral and variance accounts, as well as an earnings sharing mechanism that requires Enbridge Gas to share equally with customers, any earnings in excess of 150 basis points over the annual OEB approved return on equity. FINANCIAL STATEMENT EFFECTS Accounting for rate-regulated activities has resulted in the recognition of the following significant regulatory assets and liabilities on the Consolidated Statements of Financial Position: December 31, Recovery/Refund Period Ends 2019 2018 (millions of Canadian dollars) Regulatory assets/(liabilities), net Liquids Pipelines Deferred income taxes 1 Various 1,767 1,673 Tolling deferrals Various (25 ) (28 ) Recoverable income taxes Through 2040 24 27 Pipeline future abandonment costs 2 Various (293 ) (201 ) Other deferrals Various 32 — Gas Transmission and Midstream Deferred income taxes 1 Various 511 826 Regulatory liability related to income taxes 3 Various (866 ) (912 ) Long-term debt 4 Various 108 124 Pipeline future abandonment costs 2 Various (159 ) (111 ) Other Various 215 205 Gas Distribution and Storage Deferred income taxes 1 Various 1,273 1,132 Purchased gas variance 2020 (19 ) 197 Pension plans and OPEB Various 275 118 Future removal and site restoration reserves 5 Various (1,424 ) (1,107 ) Federal carbon program 2020 145 — Long-term debt 4 Various 362 387 Constant dollar net salvage adjustment 2018 — 6 Other Various 88 (4 ) 1 The deferred income taxes balance represents the regulatory offset to deferred income tax liabilities to the extent that it is expected to be included in regulator-approved future rates and recovered from future customers. The recovery period depends on the timing of the reversal of the temporary differences. In the absence of rate-regulated accounting, this regulatory balance and the related earnings impact would not be recorded. 2 The pipeline future abandonment costs liability results from amounts collected and set aside in accordance with the CER’s LMCI to cover future abandonment costs for CER regulated Canadian pipelines. Funds collected are included in Restricted long-term investments (Note 14) .Concurrently, we reflect the future abandonment cost as a regulatory liability. The settlement of this balance will occur as pipeline abandonment costs are incurred. 3 Relates to the establishment of a regulatory liability as a result of the United States tax reform legislation enacted December 22, 2017. 4 The debt balance represents our regulatory offset to the fair value adjustment to debt that resulted from the merger with Spectra Energy. The offset is viewed as a proxy for the regulatory asset that would be recorded in the event such debt was extinguished at an amount higher than the carrying value. 5 Future removal and site restoration reserves result from amounts collected from customers by us, with the approval of the OEB, to fund future costs for removal and site restoration relating to property, plant and equipment. These costs are collected as part of depreciation charged on property, plant and equipment that is recorded in rates. The balance represents the amount that we have collected from customers, net of actual costs expended on removal and site restoration. The settlement of this balance will occur over the long-term as future removal and site restoration costs are incurred. In the absence of rate-regulated accounting, costs incurred for removal and site restoration would be charged to earnings as incurred with recognition of revenue for amounts previously collected. OTHER ITEMS AFFECTED BY RATE REGULATION Allowance for Funds Used During Construction and Other Capitalized Costs Under the pool method prescribed by certain regulators, it is not possible to identify the carrying value of the equity component of AFUDC or its effect on depreciation. Similarly, gains and losses on the retirement of certain specific fixed assets in any given year cannot be identified or quantified. Operating Cost Capitalization With the approval of regulators, certain operations capitalize a percentage of specified operating costs. These operations are authorized to charge depreciation and earn a return on the net book value of such capitalized costs in future years. In the absence of rate regulation, a portion of such operating costs would be charged to earnings in the year incurred.

ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS AND DISPOSITIONS	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
ACQUISITIONS AND DISPOSITIONS	ACQUISITIONS AND DISPOSITIONS ACQUISITIONS Spectra Energy Corp On February 27, 2017, Enbridge and Spectra Energy combined in the Merger Transaction for a purchase price of $37.5 billion . Under the terms of the Merger Transaction, Spectra Energy shareholders received 0.984 shares of Enbridge common stock for each share of Spectra Energy common stock that they owned, giving us 100% ownership of Spectra Energy. Consideration offered to complete the Merger Transaction included 691 million common shares of Enbridge at US $41.34 per share, based on the February 24, 2017 closing price on the NYSE, for a total value of $37,429 million in common shares issued to Spectra Energy shareholders, plus approximately $3 million in cash in lieu of any fractional shares, and 3.5 million share options with a fair value of $77 million , that were exchanged for Spectra Energy’s outstanding stock compensation awards. Spectra Energy, through its subsidiaries and equity affiliates, owns and operates a large and diversified portfolio of complementary natural gas-related energy assets and is one of North America’s leading natural gas infrastructure companies. Spectra Energy also owns and operates a crude oil pipeline system that connects Canadian and United States producers to refineries in the United States Rocky Mountain and Midwest regions. The Merger Transaction brought together two highly complementary platforms to create North America’s largest energy infrastructure company and meaningfully enhanced customer optionality, positioning us for long-term growth opportunities, and strengthening our balance sheet. The Merger Transaction was accounted for as a business combination under the acquisition method of accounting as prescribed by Accounting Standards Codification (ASC) 805 Business Combinations . The acquired tangible and intangible assets and assumed liabilities were recorded at their estimated fair values at the date of acquisition. The purchase price allocation was completed as at December 31, 2017 , along with the allocation of goodwill to reporting units (Note 16) . Our reporting units are equivalent to our identified segments with the exception of the previous Gas Transmission and Midstream segment, which was composed of two reporting units: gas transmission and gas midstream. The following table summarizes the estimated fair values that were assigned to the net assets of Spectra Energy: February 27, 2017 (millions of Canadian dollars) Fair value of net assets acquired: Current assets (a) 2,432 Property, plant and equipment, net (b) 33,555 Restricted long-term investments 144 Long-term investments (c) 5,000 Deferred amounts and other assets (d) 2,390 Intangible assets, net (e) 1,288 Current liabilities (a) (3,982 ) Long-term debt (d) (21,444 ) Other long-term liabilities (1,983 ) Deferred income taxes (b) (7,670 ) Noncontrolling interests (f) (8,877 ) 853 Goodwill (g) 36,656 37,509 Purchase price: Common shares 37,429 Cash 3 Fair value of outstanding earned stock compensation awards recorded in Additional paid-in capital 77 37,509 a) Accounts receivable is comprised primarily of customer trade receivables and natural gas imbalances. As such, the fair value of accounts receivable approximates the net carrying value of $1,174 million . The gross amount due of $1,190 million , of which $16 million is not expected to be collected, is included in current assets. During the fourth quarter of 2017, we identified certain transactions that were not reflected in the purchase price equation. This resulted in a $67 million and $548 million increase in current assets and current liabilities, respectively, and a $481 million decrease in long-term debt. b) We have applied the valuation methodologies described in ASC 820 Fair Value Measurements and Disclosures , to value the property, plant and equipment purchased. The fair value of Spectra Energy’s rate-regulated property, plant and equipment was determined using a market participant perspective, which is their carrying amount. The fair value of the remaining non-regulated property, plant and equipment was determined primarily using variations of the income approach, which is based on the present value of the future after-tax cash flows attributable to each non-regulated asset. Some of the more significant assumptions inherent in the development of the values, from the perspective of a market participant, include, but are not limited to, the amount and timing of projected future cash flows (including revenue and profitability); the discount rate selected to measure the risks inherent in the future cash flows; the assessment of the asset’s life cycle; the competitive trends impacting the asset; and customer turnover. During the third quarter of 2017, Spectra Energy's right-of-way agreements were reclassified from intangible assets to property, plant and equipment to conform the presentation of these agreements with our accounting policy pertaining to rights-of-way. The purchase price allocation above reflects this reclassification, which amounted to $830 million as at February 27, 2017. There is no change in the amortization period for the right-of-way agreements as a result of this reclassification. During the fourth quarter of 2017, we finalized our fair value measurement of the BC Pipeline & Field Services businesses, which resulted in decreases to property, plant and equipment of $1,955 million and deferred income tax liabilities of $661 million as at February 27, 2017. c) Long-term investments represent Spectra Energy’s 50% equity investment in DCP Midstream, Gulfstream Natural Gas System, L.L.C., NEXUS Gas Transmission, LLC (NEXUS), Steckman Ridge LP, Islander East Pipeline Company, L.L.C., Southeast Supply Header L.L.C., and 20% equity interest in PennEast Pipeline Company LLC (PennEast). The fair value of these investments was determined using an income approach. d) Fair value of long-term debt was determined based on the current underlying Government of Canada and United States Treasury interest rates on the corresponding bonds, as well as an implied credit spread based on current market conditions and resulted in an increase in the book value of debt of $1.5 billion . The fair value adjustment to long-term debt related to rate-regulated entities of $629 million also results in a regulatory offset in Deferred amounts and other assets in the Consolidated Statements of Financial Position. During the fourth quarter of 2017, deferred amounts and other assets decreased by $530 million as at February 27, 2017 due to the finalization of BC Pipelines & Field Services' fair value measurement, as discussed under (b) above. During the fourth quarter of 2017, we identified certain transactions that were not reflected in the purchase price equation. This resulted in a $481 million decrease in long-term debt, as discussed under (a) above. e) Intangible assets primarily consist of customer relationships in the non-regulated business, which represent the underlying relationship from long-term agreements with customers that are capitalized upon acquisition, determined using the income approach. Intangible assets are amortized on a straight-line basis over their expected lives. During the third quarter of 2017, intangible assets decreased by $830 million as at February 27, 2017 due to a reclassification to property, plant and equipment, as discussed under (b) above. The fair value of intangible assets acquired through the Merger Transaction, by major classes is as follows: Weighted Average Fair As at February 27, 2017 Amortization Rate Value (millions of Canadian dollars) Customer relationships 1 3.7 % 739 Project agreement 2 4.0 % 105 Software 11.1 % 329 Other 4.2 % 115 1,288 1 Represents customer relationships in the non-regulated business, which were capitalized upon acquisition. 2 Represents a project agreement between SEP, NextEra Energy, Inc., Duke Energy Corporation (Duke Energy) and Williams Partners L.P. In accordance with the agreement, payments will be made, based on our proportional ownership interest in Sabal Trail, as certain milestones of the project are met. Amortization of the intangible asset began on July 3, 2017 , when Sabal Trail was placed into service (Note 13) . f) The fair value of Spectra Energy’s noncontrolling interests includes approximately 78.4 million SEP common units outstanding to the public, valued at the February 24, 2017 closing price of US $44.88 per common unit on the NYSE, and units held by third parties in Maritimes & Northeast Pipeline, L.L.C., Sabal Trail and Algonquin Gas Transmission, L.L.C., valued based on the underlying net assets of each reporting unit and preferred stock held by third parties in Union Gas and Westcoast Energy Inc. During the third quarter of 2017, we finalized our fair value measurement of Sabal Trail, which resulted in an increase to noncontrolling interests of $85 million as at February 27, 2017. g) We recorded $36.7 billion in goodwill, which is primarily related to expected synergies from the Merger Transaction. The goodwill balance recognized is not deductible for tax purposes. Factors that contributed to the goodwill include the opportunity to expand our natural gas pipelines segment, the potential for cost and supply chain optimization synergies, existing assembled assets and work force that cannot be duplicated at the same cost by a new entrant, franchise rights and other intangibles not separately identifiable because they are inextricably linked to the provision of regulated utility service and the enhanced scale and geographic diversity which provide greater optionality and platforms for future growth. During the third quarter of 2017, goodwill increased by $85 million as at February 27, 2017 due to the finalization of the fair value measurement of Sabal Trail as discussed under (f) above. During the fourth quarter of 2017, goodwill increased by $1,824 million as at February 27, 2017 due to the finalization of the fair value measurement of BC Pipelines & Field Services as discussed under (b) above. Acquisition-related expenses incurred were approximately $231 million . Costs incurred for the year ended December 31, 2017 of $180 million were included in Operating and administrative expense in the Consolidated Statements of Earnings. Upon completion of the Merger Transaction, we began consolidating Spectra Energy. Since the closing date of February 27, 2017 through December 31, 2017, Spectra Energy has generated approximately $5,740 million in revenues and $2,574 million in earnings. Our supplemental pro forma consolidated financial information for the year ended December 31, 2017, including the results of operations for Spectra Energy as if the Merger Transaction had been completed on January 1, 2017 are as follows: Year ended December 31, 2017 (unaudited; millions of Canadian dollars) Revenues 45,669 Earnings attributable to common shareholders 1 2,902 1 Merger Transaction costs of $180 million (after-tax $131 million ) were excluded from earnings for the year ended December 31, 2017. ASSETS HELD FOR SALE Line 10 Crude Oil Pipeline In the first quarter of 2018, we satisfied the condition as set out in our agreements for the sale of our Line 10 crude oil pipeline (Line 10), which originates near Hamilton, Ontario and terminates at West Seneca, New York. Our subsidiaries, Enbridge Pipelines Inc. and EEP, own the Canadian and United States portions of Line 10, respectively, and the related assets are included in our Liquids Pipeline segment. Subject to certain regulatory approvals and customary closing conditions, the transaction is expected to close in 2020. A loss of $154 million was included within Impairment of long-lived assets on the Consolidated Statements of Earnings for the year ended December 31, 2018 in relation to measuring Line 10 assets at the lower of their carrying value or fair value less costs to sell. Montana-Alberta Tie Line In the fourth quarter of 2019, we committed to a plan to sell the Montana-Alberta Tie Line transmission assets, a 345 kilometer transmission line from Great Falls, Montana to Lethbridge, Alberta. Its related assets are included in our Renewable Power Generation segment. The purchase and sale agreement was signed in January 2020. Subject to certain regulatory approvals and customary closing conditions, the transaction is expected to close in the first quarter of 2020. Upon the reclassification and subsequent remeasurement of MATL assets as held for sale, a loss of $297 million was included within Impairment of long-lived assets on the Consolidated Statements of Earnings. Summary of Assets Held for Sale The table below summarizes the presentation of net assets held for sale in our Consolidated Statements of Financial Position: December 31, 2019 December 31, 2018 2 (millions of Canadian dollars) Accounts receivable and other (current assets held for sale) 28 117 Deferred amounts and other assets (long-term assets held for sale) 1 269 2,383 Accounts payable and other (current liabilities held for sale) — (63 ) Other long-term liabilities (long-term liabilities held for sale) — (96 ) Net assets held for sale 297 2,341 1 Included within Deferred amounts and other assets at December 31, 2019 and 2018 respectively is property, plant and equipment of $181 million and $2.1 billion . 2 Figures are inclusive of net assets held for sale at December 31, 2018 and subsequently disposed of during the year ended December 31, 2019. DISPOSITIONS St. Lawrence Gas Company, Inc. In August 2017, we entered into an agreement to sell the issued and outstanding shares of St. Lawrence Gas Company, Inc. (St. Lawrence Gas). St. Lawrence Gas assets were included in the Gas Distribution and Storage segment. On November 1, 2019 we closed the sale of St. Lawrence Gas for cash proceeds of approximately $72 million (US $55 million ). After closing adjustments, a loss on disposal of $10 million was included in Other income/(expense) in the Consolidated Statements of Earnings. Enbridge Gas New Brunswick In December 2018, we entered into an agreement for the sale of Enbridge Gas New Brunswick Limited Partnership and Enbridge Gas New Brunswick Inc. (collectively, EGNB). EGNB assets were a part of our Gas Distribution and Storage segment. On October 1, 2019 we closed the sale of EGNB to Liberty Utilities (Canada) LP, a wholly-owned subsidiary of Algonquin Power and Utilities Corp. for cash proceeds of approximately $331 million . After closing adjustments, a loss on disposal of $3 million was included in Other income/(expense) in the Consolidated Statements of Earnings. As EGNB assets represented a portion of a reporting unit, we allocated a portion of the goodwill of the reporting unit to these assets using a relative fair value approach. As such, allocated goodwill of $133 million was included in assets subsequently disposed. Canadian Natural Gas Gathering and Processing Businesses On July 4, 2018, we entered into agreements to sell our Canadian natural gas gathering and processing businesses to Brookfield Infrastructure Partners L.P. and its institutional partners for a cash purchase price of approximately $4.3 billion , subject to customary closing adjustments. Separate agreements were entered into for those facilities currently governed by provincial regulations and those governed by federal regulations (collectively, Canadian Natural Gas Gathering and Processing Businesses assets). As the Canadian Natural Gas Gathering and Processing Businesses assets represented a portion of a reporting unit, we allocated a portion of the goodwill of the reporting unit of these assets using a relative fair value approach. As a result of the goodwill allocation, the carrying value of Canadian Natural Gas Gathering and Processing Businesses assets was greater than the sale price consideration less the cost to sell and we recorded a goodwill impairment of $1,019 million on the Consolidated Statements of Earnings for the year ended December 31, 2018 . The held for sale classification represented a triggering event and required us to perform a goodwill impairment test for the related reporting unit. The results of the test did not indicate any additional goodwill impairment. On October 1, 2018, we closed the sale of the provincially regulated facilities for proceeds of approximately $2.5 billion . After closing adjustments, a gain on disposal of $34 million before tax was included in Other income/(expense) in the Consolidated Statements of Earnings for the year ended December 31, 2018 . On December 31, 2019 , we closed the sale of the federally regulated facilities for proceeds of approximately $1.7 billion . After closing adjustments, a loss on disposal of $268 million before tax was included in Other income/(expense) in the Consolidated Statements of Earnings for the year ended December 31, 2019 . As these assets represented a portion of a reporting unit, we allocated a portion of the goodwill of the reporting unit to these assets using a relative fair value approach. As such, allocated goodwill of $55 million was included in assets subsequently disposed. Renewable Assets On August 1, 2018, we closed the sale of a 49% interest in all of our Canadian renewable assets, a 49% interest in two United States renewable assets and 49% of our interest in the Hohe See Offshore wind power project and its subsequent expansion, both concurrently under construction in Germany, (collectively, the Renewable Assets) to the CPPIB. Total cash proceeds from the transaction were $1.75 billion . In addition, CPPIB will fund their pro-rata share of the remaining capital expenditures on the Hohe See Offshore wind power project. We maintain a 51% interest in the Renewable Assets and will continue to manage, operate and provide administrative services for these assets. A loss on disposal of $20 million ( €14 million ) was included in Other income/(expense) in the Consolidated Statements of Earnings for the year ended December 31, 2018 for the sale of 49% of our interest in the Hohe See Offshore wind power project and its subsequent expansion. Subsequent to the sale, the remaining interests in these assets continue to be accounted for as an equity method investment, and are a part of our Renewable Power Generation segment. Gains of $62 million and $17 million (US $13 million ) were included in Additional paid-in capital in the Consolidated Statements of Financial Position for the year ended December 31, 2018 for the sale of 49% interest in the Canadian and United States renewable assets, respectively. Also, a deferred income tax recovery of $267 million ( $196 million attributable to us) was recorded in the year ended December 31, 2018 as a result of the agreement entered into during the second quarter of 2018 for the Renewable Assets (Note 25) . Midcoast Operating, L.P. On August 1, 2018, we closed the sale of MOLP to AL Midcoast Holdings, LLC (an affiliate of ArcLight Capital Partners, LLC) for total cash proceeds of $1.4 billion (US $1.1 billion ). After closing adjustments recorded in the fourth quarter of 2018, a loss on disposal of $41 million (US $32 million ) was included in Other income/(expense) in the Consolidated Statements of Earnings. MOLP conducted our United States natural gas and natural gas liquids gathering, processing, transportation and marketing businesses, and was a part of our Gas Transmission and Midstream segment. Upon the reclassification and subsequent re-measurement of MOLP assets as held for sale, an asset impairment loss of $4.4 billion and a related goodwill impairment of $102 million , were included in the Consolidated Statement of Earnings for the year ended December 31, 2017 . As a result of entering into a definitive sales agreement, the fair value of the assets held for sale as at March 31, 2018 were revised based on the sale price. Accordingly, we recorded a loss of $913 million included within Impairment of long-lived assets on the Consolidated Statements of Earnings for the year ended December 31, 2018 . In the second quarter of 2018, our equity method investment in the Texas Express NGL pipeline system, also met the conditions for assets held for sale. The $447 million carrying value of Texas Express NGL pipeline system equity investment and an allocated goodwill of $262 million , were included within the disposal group as at June 30, 2018 and subsequently disposed on August 1, 2018. Upon closing of the sale, we also recorded a liability of $387 million (US $298 million ) for future volume commitments retained by us. The associated loss is included in the loss on disposal of $41 million discussed above. As at December 31, 2019 and December 31, 2018 respectively, $299 million (US $230 million ) and $375 million (US $274 million ) were included in liabilities on the Consolidated Statements of Financial Position. Sandpiper Project During the years ended December 31, 2018 and 2017 , we sold unused pipe related to the Sandpiper for cash proceeds of approximately $38 million ( US$30 million ) and $148 million (US $111 million ), respectively. Gains on disposal of $29 million ( US$22 million ) and $83 million (US $63 million ) before tax were included in Operating and administrative expense in the Consolidated Statements of Earnings for the years ended December 31, 2018 and 2017 , respectively. These assets were a part of our Liquids Pipelines segment. Olympic Pipeline On July 31, 2017, we completed the sale of our interest in Olympic Pipeline for cash proceeds of approximately $203 million (US $160 million ). A gain on disposal of $27 million (US $21 million ) before tax was included in Other income/(expense) in the Consolidated Statements of Earnings for the year ended December 31, 2017 . This interest was a part of our Liquids Pipelines segment. Ozark Pipeline On March 1, 2017, we completed the sale of the Ozark Pipeline assets to a subsidiary of MPLX LP for cash proceeds of approximately $294 million (US $220 million ), including reimbursement of costs. A gain on disposal of $14 million (US $10 million ) before tax was included in Operating and administrative expense in the Consolidated Statements of Earnings for the year ended December 31, 2017 . These assets were a part of our Liquids Pipelines segment.

ACCOUNTS RECEIVABLE AND OTHER

ACCOUNTS RECEIVABLE AND OTHER	12 Months Ended
	Dec. 31, 2019
Receivables [Abstract]
ACCOUNTS RECEIVABLE AND OTHER	ACCOUNTS RECEIVABLE AND OTHER December 31, 2019 2018 (millions of Canadian dollars) Trade receivables and unbilled revenues 1 5,164 4,711 Short-term portion of derivative assets 327 498 Other 1,290 1,308 6,781 6,517 1 Net of allowance for doubtful accounts of $50 million and $64 million as at December 31, 2019 and 2018 , respectively.

INVENTORY

INVENTORY	12 Months Ended
	Dec. 31, 2019
Inventory Disclosure [Abstract]
INVENTORY	INVENTORY December 31, 2019 2018 (millions of Canadian dollars) Natural gas 696 776 Crude oil 542 482 Other commodities 61 81 1,299 1,339 Adjustments of $188 million , $327 million and $58 million were included in Commodity costs on the Consolidated Statements of Earnings for the years ended December 31, 2019 , 2018 and 2017 , respectively, to reduce inventory to market value.

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT AND EQUIPMENT Weighted Average December 31, Depreciation Rate 2019 2018 1 (millions of Canadian dollars) Pipelines 2.5 % 56,330 51,647 Facilities and equipment 2.7 % 29,287 27,149 Land and right-of-way 2 2.0 % 2,947 2,614 Gas mains, services and other 2.7 % 12,194 12,088 Storage 2.3 % 2,748 2,730 Wind turbines, solar panels and other 4.1 % 4,914 5,015 Other 6.4 % 1,486 1,463 Under construction — % 4,057 9,698 Total property, plant and equipment 3 113,963 112,404 Total accumulated depreciation (20,240 ) (17,864 ) Property, plant and equipment, net 93,723 94,540 1 Asset categories were revised and collapsed in the current year. 2018 comparative figures have been reclassified to conform to current year's asset classifications. 2 The measurement of weighted average depreciation rate excludes non-depreciable assets. 3 Certain assets were reclassified as held for sale as at December 31, 2019 and December 31, 2018 (Note 8) . Depreciation expense for the years ended December 31, 2019 , 2018 and 2017 was $3.0 billion , $2.9 billion and $2.9 billion , respectively. IMPAIRMENT Access Northeast Project In 2019, we announced that we terminated the agreements with Eversource and National Grid related to the Access Northeast project. As a result, we recognized an impairment loss of $105 million for the year ended December 31, 2019 , which is included in Impairment of long-lived assets in the Consolidated Statements of Earnings. Access Northeast is part of our Gas Transmission and Midstream segment. Impairment charges were based on the amount by which the carrying values of the assets exceeded fair value, determined using expected discounted future cash flows.

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	12 Months Ended
	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES CONSOLIDATED VARIABLE INTEREST ENTITIES Enbridge Canadian Renewable LP (ECRLP) ECRLP, an entity which we have a 51% ownership in, is a VIE as its limited partners lack substantive kick-out rights or participating rights. Because we have the power to direct the activities of ECRLP, we are exposed to potential losses, and we have the right to receive benefits from ECRLP, we are considered the primary beneficiary. Renewable Power Generation Through various subsidiaries, we have a majority ownership interest in Magic Valley, Wildcat, Keechi Wind Project (Keechi), New Creek and Chapman Ranch wind facilities. These wind facilities are considered VIEs due to the members’ lack of substantive kick-out rights and participating rights. We are the primary beneficiary of these VIEs by virtue of our power to direct the activities that most significantly impact the economic performance of the wind facilities, and our obligation to absorb losses and the right to receive benefits that are significant. Enbridge Holdings (DakTex) L.L.C. Enbridge Holdings (DakTex) L.L.C. (DakTex) is owned 75% by a wholly-owned subsidiary of Enbridge and 25% by EEP, through which we have an effective 27.6% interest in the equity investment, Bakken Pipeline System (Note 13) . EEP is the primary beneficiary because it has the power to direct DakTex’s activities that most significantly impact its economic performance. We consolidate EEP and by extension, also consolidate DakTex. Enbridge Income Partners LP (EIPLP) EIPLP, formed in 2002, was involved in the generation, transportation and storage of energy through interests in its Liquids Pipelines business, including the Canadian Mainline, the Regional Oil Sands System, an interest in the Alliance Pipeline, which transports natural gas, and its renewable and alternative power generation facilities. EIPLP was wound up in 2019 and thus is no longer a VIE. Enbridge Income Fund (the Fund) The Fund is an unincorporated open-ended trust established by a trust indenture under the laws of the Province of Alberta. In 2019, an amendment to the Fund's governing documents was executed which resulted in the Fund no longer being considered a VIE. Enbridge Commercial Trust (ECT) In 2019, an amendment to ECT's governing documents was executed which resulted in ECT no longer being considered a VIE. Other Limited Partnerships By virtue of limited partners' lack of substantive kick-out rights and participating rights, substantially all limited partnerships wholly-owned by us and/or our subsidiaries are considered VIEs, including EEP and SEP. As these entities are 100% owned and directed by us with no third parties having the ability to direct any of the significant activities, we are considered the primary beneficiary. The following table includes assets to be used to settle liabilities of our consolidated VIEs and liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit as the primary beneficiary. These assets and liabilities are included in the Consolidated Statements of Financial Position. December 31, 2019 1 2018 (millions of Canadian dollars) Assets Cash and cash equivalents 208 506 Restricted cash 1 61 Accounts receivable and other 76 2,006 Accounts receivable from affiliates — 38 Inventory 4 244 289 2,855 Property, plant and equipment, net 3,392 72,349 Long-term investments 15 6,481 Restricted long-term investments 69 244 Deferred amounts and other assets 4 3,156 Intangible assets, net 124 705 Goodwill — 29 Deferred income taxes — 131 3,893 85,950 Liabilities Short-term borrowings — 275 Accounts payable and other 56 2,925 Accounts payable to affiliates — 4 Interest payable — 303 Environmental liabilities — 22 Current portion of long-term debt — 1,034 56 4,563 Long-term debt — 29,577 Other long-term liabilities 130 5,074 Deferred income taxes 5 6,911 191 46,125 Net assets before noncontrolling interests 3,702 39,825 1 Excludes assets and liabilities of EEP and SEP following the subsidiary guarantees agreement entered on January 22, 2019 (Note 32). We do not have an obligation to provide financial support to any of the consolidated VIEs. UNCONSOLIDATED VARIABLE INTEREST ENTITIES We currently hold several equity investments in limited partnerships that are assessed to be VIEs due to limited partners not having substantive kick-out rights or participating rights. We have determined that we do not have the power to direct the activities of the VIEs that most significantly impact the VIEs’ economic performance. Specifically, the power to direct the activities of a majority of these VIEs is shared amongst the partners. Each partner has representatives that make up an executive committee that makes significant decisions for the VIE and none of the partners may make major decisions unilaterally. The carrying amount of our interest in VIEs that are unconsolidated and our estimated maximum exposure to loss as at December 31, 2019 and 2018 are presented below: Carrying Amount of Investment Enbridge’s Maximum Exposure to December 31, 2019 in VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 1 267 331 Eolien Maritime France SAS 2 67 725 Enbridge Renewable Infrastructure Investments S.a.r.l. 3 141 2,720 Gray Oak Holdings LLC 4 463 935 PennEast Pipeline Company, LLC 5 106 368 Rampion Offshore Wind Limited 6 600 620 Vector Pipeline L.P. 7 195 392 Other 8 57 57 1,896 6,148 Carrying Amount of Investment Enbridge’s Maximum Exposure to December 31, 2018 in VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 1 311 375 Eolien Maritime France SAS 2 68 784 Enbridge Renewable Infrastructure Investments S.a.r.l. 3 127 3,037 Illinois Extension Pipeline Company, L.L.C. 8 724 724 NEXUS Gas Transmission, LLC 9 1,757 2,668 PennEast Pipeline Company, LLC 5 97 385 Rampion Offshore Wind Limited 6 638 648 Vector Pipeline L.P. 7 198 301 Other 8 27 27 3,947 8,949 1 At December 31, 2019 and 2018, the maximum exposure to loss includes a guarantee issued by us for our respective share of the VIE’s borrowing on a bank credit facility. 2 At December 31, 2019 and 2018, the maximum exposure to loss includes the portion of our parental guarantee that has been committed in project construction contracts for which we would be liable in the event of default by the VIE and an outstanding affiliate loan receivable for $166 million and $202 million held by us as at December 31, 2019 and 2018, respectively. 3 At December 31, 2019 and 2018, the maximum exposure to loss includes the portion of our parental guarantee that has been committed in project construction contracts for which we would be liable in the event of default by the VIE and an outstanding affiliate loan receivable for $766 million and $461 million held by us as at December 31, 2019 and 2018, respectively. 4 At December 31, 2019 , the maximum exposure to loss includes our portion of project construction costs. 5 At December 31, 2019 and 2018, the maximum exposure to loss includes the remaining expected contributions to the joint venture. 6 At December 31, 2019 and 2018, the maximum exposure to loss includes the portion of our parental guarantee that has been committed in project construction contracts for which we would be liable in the event of default by the VIE. 7 At December 31, 2019 and 2018, the maximum exposure to loss includes the carrying value of an outstanding affiliate loan receivable for $92 million and $102 million held by us as at December 31, 2019 and 2018, respectively, in addition to us providing a credit facility for $105 million as at December 31, 2019. 8 At December 31, 2019 and 2018, the maximum exposure to loss is limited to our equity investment as these companies are in operation and self-sustaining. 9 As at December 31, 2018, the maximum exposure to loss includes the remaining expected contributions to the joint venture and parental guarantees for our portion of capacity lease agreements. We do not have an obligation to and did not provide any additional financial support to the VIEs during the years ended December 31, 2019 and 2018 . Gray Oak Holdings LLC In December 2018, Enbridge acquired an effective 22.8% interest in the Gray Oak crude oil pipeline through acquisition of a 35% membership interest in Gray Oak Holdings LLC (Gray Oak Holdings), which operates the Gray Oak crude oil pipeline from Texas to the Gulf coast of the United States. Gray Oak Holdings is a VIE as it does not have sufficient equity at risk to finance its activities and requires subordinated financial support from Enbridge and other partners. We have determined that we do not have the power to direct the activities of Gray Oak Holdings that most significantly impact its economic performance. Specifically, the power to direct the activities of the VIE is shared amongst the partners. Each partner has representatives that make up an executive committee that makes the significant decisions for the VIE and none of the partners may make significant decisions unilaterally. Therefore, the VIE is accounted for as an unconsolidated VIE. NEXUS Gas Transmission, LLC NEXUS is a joint venture that engages in transmission of natural gas received from Appalachian shale gas supplies to markets in the United States midwest, as well as Ontario, Canada was previously classified as a VIE. The NEXUS pipeline construction was completed and the pipeline was placed into service in October 2018. After NEXUS received the last significant equity contribution, it became capable of financing its own operations without any additional subordinated financial support. As a result, it was concluded that NEXUS was no longer a VIE due to sufficient equity at risk to finance its activities. Illinois Extension Pipeline Company, L.L.C. Illinois Extension Pipeline Company, L.L.C. owns the Southern Access Extension Pipeline. It was previously classified as a VIE. After Illinois Extension Pipeline Company, L.L.C. received the last significant equity contribution, it became capable of financing its own operations without any additional subordinated financial support. As a result, it was concluded that Illinois Extension Pipeline Company, L.L.C. was no longer a VIE due to sufficient equity at risk to finance its activities.

LONG-TERM INVESTMENTS

LONG-TERM INVESTMENTS	12 Months Ended
	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
LONG-TERM INVESTMENTS	LONG-TERM INVESTMENTS Ownership December 31, Interest 2019 2018 (millions of Canadian dollars) EQUITY INVESTMENTS Liquids Pipelines MarEn Bakken Company L.L.C. 1 75.0 % 1,892 2,039 Gray Oak Holdings L.L.C. 2 35.0 % 463 — Seaway Crude Pipeline System 50.0 % 2,907 3,113 Illinois Extension Pipeline Company, L.L.C. 3 65.0 % 662 724 Other 30.0% - 43.8% 73 97 Gas Transmission and Midstream Alliance Pipeline 50.0 % 310 368 Aux Sable 42.7% - 50.0% 267 311 DCP Midstream, LLC 50.0 % 2,193 2,368 Gulfstream Natural Gas System, L.L.C. 50.0 % 1,213 1,289 NEXUS Gas Transmission, LLC 50.0 % 1,778 1,757 Offshore - various joint ventures 22.0% - 74.3% 362 400 PennEast Pipeline Company LLC 20.0 % 106 97 Sabal Trail Transmission, LLC 50.0 % 1,533 1,586 Southeast Supply Header L.L.C. 50.0 % 484 519 Steckman Ridge LP 49.5 % 222 237 Vector Pipeline L.P. 60.0 % 195 198 Other 33.3% - 50.0% 5 6 Gas Distribution and Storage Noverco Common Shares 38.9 % 95 — Other 50.0 % 14 15 Renewable Power Generation Eolien Maritime France SAS 50.0 % 67 68 Enbridge Renewable Infrastructure Investments S.a.r.l. 4 51.0 % 141 127 Rampion Offshore Wind Project 24.9 % 600 638 Other 21.0% - 50.0% 127 72 Eliminations and Other Other 42.7% - 50% 16 10 OTHER LONG-TERM INVESTMENTS Gas Distribution and Storage Noverco Preferred Shares 580 478 Renewable Power Generation Emerging Technologies and Other 78 80 Eliminations and Other Other 145 110 16,528 16,707 1 Owns 49% interest in Bakken Pipeline Investments L.L.C., which owns 75% of the Bakken Pipeline System resulting in a 27.6% effective interest in the Bakken Pipeline System. 2 In December 2018 we acquired an effective 22.8% interest in the Gray Oak crude oil pipeline through acquisition of a 35% membership interest in Gray Oak Holdings, L.L.C. (Note 12). 3 Owns the Southern Access Extension Project. 4 In 2018 we sold a 49% interest in the Hohe See Offshore wind facilities to CPPIB, reducing our effective interest in the project to 25.5% . Equity investments include the unamortized excess of the purchase price over the underlying net book value of the investees’ assets at the purchase date. As at December 31, 2019 , this comprised of $2.1 billion in Goodwill and $681 million in amortizable assets. As at December 31, 2018 , this comprised of $2.2 billion in Goodwill and $706 million in amortizable assets. For the years ended December 31, 2019 , 2018 and 2017 , distributions received from equity investments were $2.2 billion , $2.8 billion and $1.4 billion , respectively. Summarized combined financial information of our interest in unconsolidated equity investments (presented at 100%) is as follows: Year Ended December 31, 2019 2018 2017 Seaway Other Total Seaway Other Total Seaway Other Total (millions of Canadian dollars) Operating revenues 1,252 14,435 15,687 966 18,251 19,217 959 15,254 16,213 Operating expenses 428 12,725 13,153 212 15,422 15,634 286 12,911 13,197 Earnings 818 2,198 3,016 646 2,308 2,954 672 2,056 2,728 Earnings attributable to Enbridge 409 950 1,359 323 1,059 1,382 336 926 1,262 December 31, 2019 December 31, 2018 Seaway Other Total Seaway Other Total (millions of Canadian dollars) Current assets 107 2,374 2,481 113 3,176 3,289 Non-current assets 3,404 45,538 48,942 3,585 45,531 49,116 Current liabilities 136 3,911 4,047 123 5,413 5,536 Non-current liabilities 45 18,081 18,126 16 15,859 15,875 Noncontrolling interests — 2,779 2,779 — 3,479 3,479 Noverco Inc. As at December 31, 2019 and 2018 , we owned an equity interest in Noverco through ownership of 38.9% of its common shares and an investment in preferred shares. The preferred shares are entitled to a cumulative preferred dividend based on the average yield of Government of Canada bonds maturing in 10 years plus a margin of 4.38% . As at December 31, 2019 and 2018 , Noverco owned an approximate 0.5% and 1.4% reciprocal shareholding in our common shares, respectively. Noverco sold 11.6 million common shares in January 2019 and 4.4 million common shares in December 2018. Shares purchased and sold were treated as treasury stock on the Consolidated Statements of Changes in Equity. As a result of Noverco’s reciprocal shareholding in our common shares, as at December 31, 2019 and 2018 , we had an indirect pro-rata interest of 0.2% and 0.5% , respectively, in our own shares. Both the equity investment in Noverco and shareholders’ equity have been reduced by the reciprocal shareholding of $51 million and $88 million as at December 31, 2019 and 2018 . Noverco records dividends paid from us as dividend income and we eliminate these dividends from our equity earnings of Noverco. We record our pro-rata share of dividends paid by us to Noverco as a reduction of dividends paid and an increase in our investment in Noverco.

RESTRICTED LONG-TERM INVESTMENT

RESTRICTED LONG-TERM INVESTMENTS	12 Months Ended
	Dec. 31, 2019
Assets Held-in-trust [Abstract]
RESTRICTED LONG-TERM INVESTMENTS	RESTRICTED LONG-TERM INVESTMENTS Effective January 1, 2015, we began collecting and setting aside funds to cover future pipeline abandonment costs for all CER regulated pipelines as a result of the CER’s regulatory requirements under LMCI. The funds collected are held in trusts in accordance with the CER decision. The funds collected from shippers are reported within Transportation and other services revenues on the Consolidated Statements of Earnings and Restricted long-term investments on the Consolidated Statements of Financial Position. Concurrently, we reflect the future abandonment cost as an increase to Operating and administrative expense on the Consolidated Statements of Earnings and Other long-term liabilities on the Consolidated Statements of Financial Position. We routinely invest excess cash and various restricted balances in securities such as commercial paper, bankers acceptances, corporate debt securities, Canadian equity securities, treasury bills and money market securities in the United States and Canada. As at December 31, 2019 and 2018 , we had restricted long-term investments held in trust and classified as available for sale or held to maturity of $434 million and $323 million , respectively. Within Other long-term liabilities we had estimated future abandonment costs related to LMCI of $454 million and $328 million as at December 31, 2019 and 2018

INTANGIBLE ASSETS

INTANGIBLE ASSETS	12 Months Ended
	Dec. 31, 2019
Intangible Assets, Net (Excluding Goodwill) [Abstract]
INTANGIBLE ASSETS	INTANGIBLE ASSETS The following table provides the weighted average amortization rate, gross carrying value, accumulated amortization and net carrying value for each of our major classes of intangible assets: Weighted Average Accumulated December 31, 2019 1 Amortization Rate Cost Amortization Net (millions of Canadian dollars) Customer relationships 5.4 % 861 (231 ) 630 Power purchase agreements 4.5 % 64 (16 ) 48 Project agreement 2 4.0 % 156 (16 ) 140 Software 11.2 % 1,988 (1,014 ) 974 Other intangible assets 3 2.9 % 463 (82 ) 381 3,532 (1,359 ) 2,173 Weighted Average Accumulated December 31, 2018 1 Amortization Rate Cost Amortization Net (millions of Canadian dollars) Customer relationships 5.7 % 889 (187 ) 702 Power purchase agreements 5.4 % 82 (15 ) 67 Project agreement 2 4.0 % 164 (10 ) 154 Software 10.0 % 1,902 (875 ) 1,027 Other intangible assets 3 2.0 % 485 (63 ) 422 3,522 (1,150 ) 2,372 1 Certain assets were reclassified as held for sale as at December 31, 2019 and December 31, 2018 (Note 8) . 2 Represents a project agreement acquired from the Merger Transaction (Note 8) . 3 The measurement of weighted average amortization rate excludes non-depreciable intangible assets. For the years ended December 31, 2019 , 2018 and 2017 , our amortization expense related to intangible assets totaled $296 million , $281 million and $280 million , respectively. The following table presents our expected amortization expense associated with existing intangible assets for the years indicated as follows: 2020 2021 2022 2023 2024 Forecast of amortization expense (millions of Canadian dollars) 292 263 238 216 195

GOODWILL

GOODWILL	12 Months Ended
	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
GOODWILL	GOODWILL Liquids Pipelines Gas Gas Renewable Power Generation Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Gross Cost Balance at January 1, 2018 7,786 21,539 5,679 — 2 13 35,019 Disposition — (628 ) — — — — (628 ) Allocation to assets held for sale — (55 ) (133 ) — — — (188 ) Foreign exchange and other 538 1,482 (183 ) — — — 1,837 Balance at December 31, 2018 8,324 22,338 5,363 — 2 13 36,040 Foreign exchange and other (373 ) (933 ) — — — — (1,306 ) Balance at December 31, 2019 7,951 21,405 5,363 — 2 13 34,734 Accumulated Impairment Balance at January 1, 2018 — (542 ) (7 ) — — (13 ) (562 ) Impairment — (1,019 ) — — — — (1,019 ) Balance at December 31, 2018 — (1,561 ) (7 ) — — (13 ) (1,581 ) Balance at December 31, 2019 — (1,561 ) (7 ) — — (13 ) (1,581 ) Carrying Value Balance at December 31, 2018 8,324 20,777 5,356 — 2 — 34,459 Balance at December 31, 2019 7,951 19,844 5,356 — 2 — 33,153 IMPAIRMENT Gas Transmission and Midstream Canadian Natural Gas Gathering and Processing Businesses During the year ended December 31, 2018, we recorded a goodwill impairment charge of $1,019 million related to our Canadian Natural Gas Gathering and Processing Businesses assets which were classified as held for sale in the third quarter of 2018. The provincially regulated assets were subsequently sold in the fourth quarter of 2018 ( Note 8 ). As these assets represented a portion of a reporting unit, we allocated a portion of the goodwill of the reporting unit to these assets using a relative fair value approach. In connection with the write-down of the carrying values of the assets held for sale to its sale price consideration less costs to sell, the related goodwill was impaired. We also performed a goodwill impairment test for the related reporting unit resulting in no additional impairment charge. US Midstream During the year ended December 31, 2017, we recorded a goodwill impairment charge of $102 million related to certain assets in our Gas Transmission and Midstream segment classified as held for sale ( Note 8 ) . Goodwill was allocated to certain disposal groups qualifying as a business based on a relative fair value approach. In connection with the write-down of the carrying values of the assets held for sale to its fair value less costs to sell, the related goodwill was impaired. The fair values of these assets were estimated using the discounted cash flow method, which was negatively impacted by a prolonged decline in commodity prices and deteriorating business performance. We also performed goodwill impairment testing on the associated gas midstream reporting unit resulting in no additional impairment charge. The estimate of the gas midstream reporting unit’s fair value required the use of significant unobservable inputs representative of a Level 3 fair value measurement, including assumptions related to the future performance of the reporting unit. DISPOSITIONS In 2018 , we derecognized $262 million of goodwill on the disposition of Midcoast Operating, L.P. and its subsidiaries and $366 million on the disposition of the provincially regulated facilities of our Canadian Natural Gas Gathering and Processing Business ( Note 8 ) . ACQUISITIONS In 2017, we recognized $36.7 billion of goodwill on the Merger Transaction ( Note 8 ) .

ACCOUNTS PAYABLE AND OTHER

ACCOUNTS PAYABLE AND OTHER	12 Months Ended
	Dec. 31, 2019
Payables and Accruals [Abstract]
ACCOUNTS PAYABLE AND OTHER	ACCOUNTS PAYABLE AND OTHER December 31, 2019 2018 (millions of Canadian dollars) Trade payables and operating accrued liabilities 4,536 4,604 Construction payables and contractor holdbacks 804 804 Current derivative liabilities 920 1,234 Dividends payable 1,678 1,539 Taxes payable 890 801 Current deferred credits 652 850 Other 583 31 10,063 9,863

DEBT

DEBT	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
DEBT	DEBT On January 22, 2019, Enbridge entered into supplemental indentures with its wholly-owned subsidiaries, SEP and EEP (together, the Partnerships), pursuant to which Enbridge fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations of the Partnerships with respect to the outstanding series of notes issued under the respective indentures of the Partnerships. Concurrently, the Partnerships entered into a subsidiary guarantee agreement pursuant to which they fully and unconditionally guaranteed, on a senior unsecured basis, the outstanding series of senior notes of Enbridge. See Note 32 - Condensed Consolidating Financial Information for further discussion. Weighted Average December 31, Interest Rate 22 Maturity 2019 2018 (millions of Canadian dollars) Enbridge Inc. United States dollar senior notes 1 3.8 % 2022-2049 8,689 6,419 Medium-term notes 4.2 % 2020-2064 7,623 7,323 Fixed-to-floating rate subordinated term notes 2,3 5.9 % 2077-2078 6,550 6,771 Floating rate notes 4 2020 1,556 2,389 Commercial paper and credit facility draws 5 1.9 % 2021-2024 5,210 1,999 Other 6 5 4 Enbridge (U.S.) Inc. Commercial paper and credit facility draws 7 2.1 % 2021-2024 1,734 1,065 Enbridge Energy Partners, L.P. Senior notes 8 6.0 % 2021-2045 3,955 6,214 Junior subordinated notes 9 — 546 Commercial paper and credit facility draws 10 — 1,044 Enbridge Gas Distribution Inc. 11 Medium-term notes — 3,695 Debentures — 85 Commercial paper and credit facility draws — 750 Enbridge Gas Inc. 11 Medium-term notes 4.2 % 2020-2050 7,685 — Debentures 9.1 % 2024-2025 210 — Commercial paper and credit facility draws 2.0 % 2021 898 — Enbridge Pipelines (Southern Lights) L.L.C. Senior notes 12 4.0 % 2040 1,129 1,257 Enbridge Pipelines Inc. Medium-term notes 13 4.2 % 2020-2049 5,125 4,225 Debentures 8.2 % 2024 200 200 Commercial paper and credit facility draws 14 2.0 % 2021 2,030 2,200 Enbridge Southern Lights LP Senior notes 4.0 % 2040 272 289 Spectra Energy Capital, LLC Senior notes 15 7.1 % 2032-2038 224 236 Spectra Energy Partners, LP Senior secured notes 16 6.1 % 2020 143 150 Senior notes 17 4.2 % 2020-2048 8,481 8,249 Floating rate notes 18 2020 519 546 Commercial paper and credit facility draws 19 — 2,065 Union Gas Limited 11 Medium-term notes — 3,290 Debentures — 125 Commercial paper and credit facility draws — 275 Westcoast Energy Inc. Senior secured notes — 33 Medium-term notes 4.5 % 2020-2041 1,875 2,175 Debentures 8.6 % 2020-2026 375 375 Fair value adjustment - Merger Transaction 844 964 Other 20 (369 ) (348 ) Total debt 64,963 64,610 Current maturities (4,404 ) (3,259 ) Short-term borrowings 21 (898 ) (1,024 ) Long-term debt 59,661 60,327 1 2019 - US $6,700 million ; 2018 - US $4,700 million . 2 2019 - $2,400 million and US $3,200 million ; 2018 - $2,400 million and US $3,200 million . For the initial 10 years , the notes carry a fixed interest rate. Subsequently, the interest rate will be floating and set to equal the Canadian Dollar Offered Rate (CDOR) or the London Interbank Offered Rate (LIBOR) plus a margin. 3 The notes would be converted automatically into Conversion Preference Shares in the event of bankruptcy and related events. 4 2019 - US $1,200 million ; 2018 - $750 million and US $1,200 million . Carries an interest rate equal to the three-month Bankers' Acceptance Rate plus a margin of 59 basis points or LIBOR plus a margin of 40 or 70 basis points. 5 2019 - $5,210 million ; 2018 - $1,906 million and US $69 million . 6 Primarily capital lease obligations. 7 2019 - US $1,337 million ; 2018 - US $780 million . 8 2019 - US $3,050 million ; 2018 - US $4,550 million . 9 2018 - US $400 million . 10 2018 - US $764 million . 11 Reflects the amalgamation of EGD and Union Gas into Enbridge Gas Inc . 12 2019 - US $871 million ; 2018 - US $920 million . 13 Included in medium-term notes is $100 million with a maturity date of 2112. 14 2019 - $1,570 million and US $355 million ; 2018 - $1,905 million and US $216 million . 15 2019 - US $173 million ; 2018 - US $173 million . 16 2019 - US $110 million ; 2018 - US $110 million . 17 2019 - US $6,540 million ; 2018 - US $6,040 million . 18 2019 - US $400 million ; 2018 - US $400 million . Carries an interest rate equal to the three-month LIBOR plus a margin of 70 basis points. 19 2018 - US $1,512 million . 20 Primarily unamortized discounts and debt issuance costs. 21 Weighted average interest rates on outstanding commercial paper were 2.0% as at December 31, 2019 ( 2018 - 2.3% ). 22 Calculated based on term notes and commercial paper and credit facility draws balances outstanding as at December 31, 2019 . SECURED DEBT Senior secured notes, totaling $143 million as at December 31, 2019 , include project financings for the Express-Platte System. Express-Platte System notes payable are secured by the assignment of the Express-Platte System transportation receivables and by the Canadian portion of the Express-Platte pipeline system assets. CREDIT FACILITIES The following table provides details of our committed credit facilities as at December 31, 2019 : Total Maturity Facilities Draws 1 Available (millions of Canadian dollars) Enbridge Inc. 2021-2024 6,993 5,210 1,783 Enbridge (U.S.) Inc. 2021-2024 7,132 1,734 5,398 Enbridge Pipelines Inc. 2021 2 3,000 2,030 970 Enbridge Gas Inc. 2021 2 2,000 898 1,102 Total committed credit facilities 19,125 9,872 9,253 1 Includes facility draws and commercial paper issuances that are back-stopped by the credit facility. 2 Maturity date is inclusive of the one year term out option. On February 7, 2019 and February 8, 2019, we terminated certain Canadian and United States dollar credit facilities, including facilities held by Enbridge, Enbridge Gas, EEP and SEP. We also increased existing facilities or obtained new facilities to replace the terminated ones under Enbridge, Enbridge (U.S.) Inc. and Enbridge Gas. As a result, our total credit facility availability increased by approximately $444 million . On May 16, 2019, Enbridge Inc. entered into a three year, non-revolving, extendible credit facility for $641 million ( ¥52.5 billion ) with a syndicate of Japanese banks. On July 18, 2019, Enbridge Inc. entered into a five year, non-revolving, bilateral credit facility for $500 million with an Asian bank. In addition to the committed credit facilities noted above, we maintain $916 million of uncommitted demand credit facilities, of which $476 million were unutilized as at December 31, 2019 . As at December 31, 2018 , we had $807 million of uncommitted credit facilities, of which $548 million were unutilized. Our credit facilities carry a weighted average standby fee of 0.1% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to the commercial paper programs and we have the option to extend such facilities, which are currently scheduled to mature from 2021 to 2024 . As at December 31, 2019 and 2018 , commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $8,974 million and $7,967 million , respectively, are supported by the availability of long-term committed credit facilities and therefore have been classified as long-term debt. LONG-TERM DEBT ISSUANCES During the years ended December 31, 2019 and 2018 , we completed the following long-term debt issuances, excluding the debt exchange discussed below: Company Issue Date Principal Amount (millions of Canadian dollars unless otherwise stated) Enbridge Inc. October 2019 2.99% medium-term notes due October 2029 $1,000 November 2019 2.50% senior notes due July 2025 US$500 November 2019 3.13% senior notes due November 2029 US$1,000 November 2019 4.00% senior notes due November 2049 US$500 March 2018 Fixed-to-floating rate subordinated notes due March 2078 1 US$850 April 2018 Fixed-to-floating rate subordinated notes due April 2078 2 $750 April 2018 Fixed-to-floating rate subordinated notes due April 2078 3 US$600 Enbridge Gas Inc. August 2019 2.37% medium-term notes due August 2029 $400 August 2019 3.01% medium-term notes due August 2049 $300 Enbridge Pipelines Inc. February 2019 3.52% medium-term notes due February 2029 $600 February 2019 4.33% medium-term notes due February 2049 $600 Spectra Energy Partners, LP August 2019 3.24% senior notes due August 2029 4 US$500 January 2018 3.50% senior notes due January 2028 5 US$400 January 2018 4.15% senior notes due January 2048 5 US$400 1 Notes mature in 60 years and are callable on or after year 10 . For the initial 10 years , the notes carry a fixed interest rate of 6.25% . Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 364 basis points from years 10 to 30 , and a margin of 439 basis points from years 30 to 60 . 2 Notes mature in 60 years and are callable on or after year 10 . For the initial 10 years , the notes carry a fixed interest rate of 6.625% . Subsequently, the interest rate will be set to equal CDOR plus a margin of 432 basis points from years 10 to 30 , and a margin of 507 basis points from years 30 to 60 . 3 Notes mature in 60 years and are callable on or after year five . For the initial five years , the notes carry a fixed interest rate of 6.375% . Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 359 basis points from years five to 10 , a margin of 384 basis points from years 10 to 25 , and a margin of 459 basis points from years 25 to 60 . 4 Issued through Algonquin Gas Transmission, LLC, an operating subsidiary of SEP. 5 Issued through Texas Eastern, a wholly-owned operating subsidiary of SEP. LONG-TERM DEBT REPAYMENTS During the years ended December 31, 2019 and 2018 , we completed the following long-term debt repayments, excluding the debt exchange discussed below: Company Retirement/Repayment Date Principal Amount Cash Consideration 1 (millions of Canadian dollars unless otherwise stated) Enbridge Inc. Repayment February 2019 4.10% medium-term notes $300 May 2019 Floating rate notes $750 September 2019 4.77% medium-term notes $400 Enbridge Energy Partners, L.P. Redemption February 2019 8.05% fixed/floating rate junior subordinated notes due 2067 US$400 December 2019 5.20% senior notes due 2020 US$500 US$504 December 2019 4.38% senior notes due 2020 US$500 US$509 Repayment March 2019 9.88% senior notes US$500 April 2018 6.50% senior notes US$400 October 2018 7.00% senior notes US$100 Enbridge Income Fund Repayment December 2018 4.00% medium-term notes $125 Enbridge Pipelines (Southern Lights) L.L.C. Repayment June and December 2019 3.98% senior notes due 2040 US$49 June and December 2018 3.98% senior notes due 2040 US$43 Enbridge Pipelines Inc. Repayment November 2019 4.49% medium-term notes $200 November 2019 4.49% medium-term notes $100 November 2018 6.62% medium-term notes $170 November 2018 6.62% medium-term notes $130 Enbridge Southern Lights LP Repayment July and December 2019 4.01% senior notes due 2040 $17 January, July and December 2018 4.01% senior notes due 2040 $27 Midcoast Energy Partners, L.P. Redemption July 2018 2 3.56% senior notes due 2019 US$75 US$76 July 2018 2 4.04% senior notes due 2021 US$175 US$182 July 2018 2 4.42% senior notes due 2024 US$150 US$161 Spectra Energy Capital, LLC Repurchase via Tender Offer March 2018 2 6.75% senior unsecured notes due 2032 US$64 US$80 March 2018 2 7.50% senior unsecured notes due 2038 US$43 US$59 Redemption March 2018 2 5.65% senior unsecured notes due 2020 US$163 US$172 March 2018 2 3.30% senior unsecured notes due 2023 US$498 US$508 Repayment April 2018 6.20% senior notes US$272 July 2018 6.75% senior notes US$118 Spectra Energy Partners, LP Repayment September 2018 2.95% senior notes US$500 Union Gas Limited Repayment April 2018 5.35% medium-term notes $200 August 2018 8.75% debentures $125 October 2018 8.65% senior debentures $75 Westcoast Energy Inc. Repayment January 2019 5.60% medium-term notes $250 January 2019 5.60% medium-term notes $50 May and November 2019 6.90% senior secured notes $26 May and November 2019 4.34% senior secured notes $5 December 2019 1.00% senior secured notes $2 May and November 2018 6.90% senior secured notes due 2019 $26 May and November 2018 4.34% senior secured notes due 2019 $9 September 2018 8.50% debentures $150 1 Cash consideration disclosed for repayments where the cash paid differs from the principal amount. 2 The loss on debt extinguishment of $64 million (US $50 million ), net of the fair value adjustment recorded upon completion of the Merger Transaction, was reported within Interest expense in the Consolidated Statements of Earnings. DEBT EXCHANGE On December 21, 2018, Enbridge and the Fund completed a transaction to exchange certain series of the Legacy Fund Notes for an equal principal amount of newly issued medium-term notes of Enbridge, having financial terms that are the same as the financial terms of the Fund Notes. DEBT COVENANTS Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at December 31, 2019 , we were in compliance with all debt covenants. INTEREST EXPENSE Year ended December 31, 2019 2018 2017 (millions of Canadian dollars) Debentures and term notes 2,783 3,011 3,011 Commercial paper and credit facility draws 273 171 206 Amortization of fair value adjustment - Spectra Energy acquisition (67 ) (131 ) (270 ) Capitalized (326 ) (348 ) (391 ) 2,663 2,703 2,556

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	ASSET RETIREMENT OBLIGATIONS Our ARO relate mostly to the retirement of pipelines, renewable power generation assets, obligations related to right-of way agreements and contractual leases for land use. The liability for the expected cash flows as recognized in the financial statements reflected discount rates ranging from 1.8% to 9.0% . A reconciliation of movements in our ARO liabilities is as follows: December 31, 2019 2018 (millions of Canadian dollars) Obligations at beginning of year 989 793 Liabilities acquired — — Liabilities disposed (59 ) (13 ) Liabilities incurred 15 145 Liabilities settled (12 ) (21 ) Change in estimate and other (417 ) 29 Foreign currency translation adjustment (18 ) 22 Accretion expense 22 34 Obligations at end of year 520 989 Presented as follows: Accounts payable and other 7 6 Other long-term liabilities 513 983 520 989

NONCONTROLLING INTERESTS

NONCONTROLLING INTERESTS	12 Months Ended
	Dec. 31, 2019
Noncontrolling Interest [Abstract]
NONCONTROLLING INTERESTS	NONCONTROLLING INTERESTS NONCONTROLLING INTERESTS The following table provides additional information regarding Noncontrolling interests as presented in our Consolidated Statements of Financial Position: December 31, 2019 2018 (millions of Canadian dollars) Algonquin Gas Transmission, L.L.C 394 518 Maritimes & Northeast Pipeline, L.L.C 579 613 Renewable energy assets 1 1,864 1,961 Westcoast Energy Inc. 2 527 841 Other — 32 3,364 3,965 1 On August 1, 2018, we closed the sale of 49% of our interest in the Renewable Assets (Note 8) . The remaining balance represents the tax equity investors' interests in Magic Valley, Wildcat, Keechi, New Creek and Chapman Ranch wind facilities, with an additional 20.0% noncontrolling interest in each of the Magic Valley and Wildcat wind facilities held by third parties as at December 31, 2019 and 2018 . 2 Represents the 16.6 million cumulative redeemable preferred shares as at December 31, 2019 and 2018, nil and 12 million cumulative first preferred shares as at December 31, 2019 and 2018, respectively, held by third parties in Westcoast Energy Inc., in addition to the 22.2% interest in Maritimes & Northeast Pipeline Limited Partnership held by third parties as at December 31, 2019 and 2018. United States Sponsored Vehicles Buy-in On August 24, 2018, we entered into a definitive agreement with SEP under which we agreed to acquire all of the outstanding public common units of SEP not already owned by us or our subsidiaries on the basis of 1.111 of our common shares for each common unit of SEP. Upon the closing of the transaction on December 17, 2018, we acquired all of the public common units of SEP and SEP became an indirect, wholly-owned subsidiary of Enbridge. The transaction is valued at $3.9 billion based on the closing price of our common shares on the New York Stock Exchange on December 14, 2018. As a result of this buy-in, we recorded a decrease in Noncontrolling interests, Additional paid-in capital and Deferred income tax liabilities of $3.0 billion , $642 million and $167 million , respectively. On September 17, 2018, we entered into definitive agreements with each of EEP and EEM under which we agreed to acquire all of the outstanding public class A common units of EEP and all of the outstanding public listed shares of EEM not already owned by us or our subsidiaries. Under the agreements, EEP public unitholders received 0.335 of our common shares for each class A common unit of EEP, and EEM public shareholders received 0.335 of our common shares for each listed share of EEM. Upon the closing of the respective transactions on December 20, 2018, we acquired all of the public Class A common units of EEP and shares of EEM, and both EEP and EEM became indirect, wholly-owned subsidiaries of Enbridge. The EEP and EEM transactions are valued at $3.0 billion and $1.3 billion , respectively, based on the closing price of our common shares on the New York Stock Exchange on December 19, 2018. As a result of the buy-ins, collectedly for EEP and EEM, we recorded an increase in Noncontrolling interests and a decrease in Additional paid-in capital and Deferred income tax liabilities of $185 million , $3.7 billion and $707 million , respectively. For discussion on the roll-up of ENF, refer to Canadian Sponsored Vehicles Buy-in under Redeemable Noncontrolling Interests below. Renewable Assets On August 1, 2018, we closed the sale of a 49% interest in all of our Canadian renewable assets and a 49% interest in two United States renewable assets to CPPIB (Note 8) . As a result, we recorded an increase in Noncontrolling interests, Additional paid-in capital and Deferred income tax liabilities of $1,183 million , $79 million and $27 million , respectively, in the third quarter of 2018. For 2018 and 2019, CPPIB's distributions and allocation of earnings were not proportionate to its ownership. SEP Incentive Distribution Rights On January 22, 2018, Enbridge and SEP announced the execution of a definitive agreement, resulting in us converting all of our ownership of incentive distribution rights (IDRs) and general partner economic interests in SEP into 172.5 million newly issued SEP common units. As part of the transaction, all of the IDRs were eliminated. As a result of this restructuring, in 2018 we recorded a decrease in Noncontrolling interests of $1.5 billion and increases in Additional paid-in capital and Deferred income tax liabilities of $1.1 billion and $333 million , respectively. Subsequently in 2018, we acquired all of the outstanding common units of SEP (refer to United States Sponsored Vehicles Buy-in above). EEP Sponsored Vehicle Strategy On April 28, 2017, we completed a strategic review of EEP and took actions including acquisition of all EEP's interest in the Midcoast assets and privatization of Midcoast Energy Partners, L.P. As a result of these actions, we recorded an increase in Noncontrolling interests of $458 million , inclusive of foreign currency translation adjustments, and a decrease in Additional paid-in capital of $421 million , net of deferred income taxes of $253 million . Westcoast Preferred Shares Redemption On March 20, 2019, Westcoast Energy Inc. exercised its right to redeem all of its outstanding 5.5% Cumulative Redeemable First Preferred Shares, Series 7 (Series 7 Shares) and all of its outstanding 5.6% Cumulative Redeemable First Preferred Shares, Series 8 (Series 8 Shares) at a price of $25.00 per Series 7 Share and $25.00 per Series 8 Share, respectively, for a total payment of $300 million . In addition, payment of $4 million was made for all accrued and unpaid dividends. As a result, we recorded a $300 million decrease in Noncontrolling interests. REDEEMABLE NONCONTROLLING INTERESTS The following table presents additional information regarding Redeemable noncontrolling interests as presented in our Consolidated Statements of Financial Position: Year ended December 31, 2018 2017 (millions of Canadian dollars) Balance at beginning of year 4,067 3,392 Earnings attributable to redeemable noncontrolling interests 117 175 Other comprehensive income/(loss), net of tax Change in unrealized loss on cash flow hedges 3 (21 ) Other comprehensive loss from equity investees 14 — Reclassification to earnings of loss on cash flow hedges — 57 Foreign currency translation adjustments 4 (6 ) Other comprehensive income/(loss), net of tax 21 30 Distributions to unitholders (300 ) (247 ) Contributions from unitholders 70 1,178 Modified retrospective adoption of accounting standard (38 ) — Net dilution gain/(loss) 76 (169 ) Redemption value adjustment 456 (292 ) Sponsored vehicle buy-in 1 (4,469 ) — Balance at end of year — 4,067 1 On November 8, 2018, we executed the definitive agreement with ENF and acquired all of the publicly held shares of ENF not already owned by us or our subsidiaries. Canadian Sponsored Vehicle Buy-in On September 17, 2018, we entered into a definitive agreement with ENF under which we would acquire all of the outstanding public common shares of ENF not already owned by us or our subsidiaries on the basis of 0.735 of our common shares and cash of $0.45 for each common share of ENF. Upon the closing of the transaction on November 8, 2018, we acquired all of the public common shares of ENF and ENF become a wholly-owned subsidiary of Enbridge. The transaction, excluding the cash component, is valued at $4.5 billion based on the closing price of our common shares on the Toronto Stock Exchange on November 7, 2018. As a result of this buy-in, we recorded a decrease in Redeemable noncontrolling interests and Additional paid-in capital of $4.5 billion and $25 million , respectively, with nil deferred tax impact. As at December 31, 2018, the balance of Redeemable noncontrolling interests was nil

SHARE CAPITAL

SHARE CAPITAL	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
SHARE CAPITAL	SHARE CAPITAL Our authorized share capital consists of an unlimited number of common shares with no par value and an unlimited number of preference shares. COMMON SHARES 2019 2018 2017 Number Number Number December 31, of Shares Amount of Shares Amount of Shares Amount (millions of Canadian dollars; number of shares in millions) Balance at beginning of year 2,022 64,677 1,695 50,737 943 10,492 Common shares issued — — — — 33 1,500 Common shares issued in Merger Transaction (Note 8) — — — — 691 37,429 Common shares issued in Sponsored Vehicle buy-in (SEP) (Note 20) — — 91 3,888 — — Common shares issued in Sponsored Vehicle buy-in (EEP) (Note 20) — — 72 3,042 — — Common shares issued in Sponsored Vehicle buy-in (EEM) (Note 20) — — 30 1,267 — — Common shares issued in Sponsored Vehicle buy-in (ENF) (Note 20) — — 104 4,530 — — Dividend Reinvestment and Share Purchase Plan — — 28 1,181 25 1,226 Shares issued on exercise of stock options 3 69 2 32 3 90 Balance at end of year 2,025 64,746 2,022 64,677 1,695 50,737 PREFERENCE SHARES 2019 2018 2017 Number Number Number December 31, of Shares Amount of Shares Amount of Shares Amount (millions of Canadian dollars; number of shares in millions) Preference Shares, Series A 5 125 5 125 5 125 Preference Shares, Series B 18 457 18 457 18 457 Preference Shares, Series C 2 43 2 43 2 43 Preference Shares, Series D 18 450 18 450 18 450 Preference Shares, Series F 20 500 20 500 20 500 Preference Shares, Series H 14 350 14 350 14 350 Preference Shares, Series J 8 199 8 199 8 199 Preference Shares, Series L 16 411 16 411 16 411 Preference Shares, Series N 18 450 18 450 18 450 Preference Shares, Series P 16 400 16 400 16 400 Preference Shares, Series R 16 400 16 400 16 400 Preference Shares, Series 1 16 411 16 411 16 411 Preference Shares, Series 3 24 600 24 600 24 600 Preference Shares, Series 5 8 206 8 206 8 206 Preference Shares, Series 7 10 250 10 250 10 250 Preference Shares, Series 9 11 275 11 275 11 275 Preference Shares, Series 11 20 500 20 500 20 500 Preference Shares, Series 13 14 350 14 350 14 350 Preference Shares, Series 15 11 275 11 275 11 275 Preference Shares, Series 17 30 750 30 750 30 750 Preference Shares, Series 19 20 500 20 500 20 500 Issuance costs (155 ) (155 ) (155 ) Balance at end of year 7,747 7,747 7,747 Characteristics of the preference shares are as follows: Dividend Rate Dividend 1 Per Share Base Redemption Value 2 Redemption and Conversion Option Date 2,3 Right to Convert Into 3,4 (Canadian dollars unless otherwise stated) Preference Shares, Series A 5.50 % $1.37500 $25 — — Preference Shares, Series B 3.42 % $0.85360 $25 June 1, 2022 Series C Preference Shares, Series C 5 3-month treasury bill plus 2.40% — $25 June 1, 2022 Series B Preference Shares, Series D 4.46 % $1.11500 $25 March 1, 2023 Series E Preference Shares, Series F 4.69 % $1.17224 $25 June 1, 2023 Series G Preference Shares, Series H 4.38 % $1.09400 $25 September 1, 2023 Series I Preference Shares, Series J 4.89 % US$1.22160 US$25 June 1, 2022 Series K Preference Shares, Series L 4.96 % US$1.23972 US$25 September 1, 2022 Series M Preference Shares, Series N 5.09 % $1.27152 $25 December 1, 2023 Series O Preference Shares, Series P 6 4.38 % $1.09476 $25 March 1, 2024 Series Q Preference Shares, Series R 6 4.07 % $1.01825 $25 June 1, 2024 Series S Preference Shares, Series 1 5.95 % US$1.48728 US$25 June 1, 2023 Series 2 Preference Shares, Series 3 6 3.74 % $0.93425 $25 September 1, 2024 Series 4 Preference Shares, Series 5 6 5.38 % US$1.34383 US$25 March 1, 2024 Series 6 Preference Shares, Series 7 6 4.45 % $1.11224 $25 March 1, 2024 Series 8 Preference Shares, Series 9 6 4.10 % $1.02424 $25 December 1, 2024 Series 10 Preference Shares, Series 11 4.40 % $1.10000 $25 March 1, 2020 Series 12 Preference Shares, Series 13 4.40 % $1.10000 $25 June 1, 2020 Series 14 Preference Shares, Series 15 4.40 % $1.10000 $25 September 1, 2020 Series 16 Preference Shares, Series 17 5.15 % $1.28750 $25 March 1, 2022 Series 18 Preference Shares, Series 19 4.90 % $1.22500 $25 March 1, 2023 Series 20 1 The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend, as declared by the Board of Directors. With the exception of Series A and Series C Preference Shares, such fixed dividend rate resets every five years beginning on the initial redemption and conversion option date. The Series 17 and Series 19 Preference Shares contain a feature where the fixed dividend rate, when reset every five years , will not be less than 5.15% and 4.90% , respectively. No other series of Preference Shares has this feature. 2 Series A Preference Shares may be redeemed any time at our option. For all other series of Preference Shares, we, may at our option, redeem all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter. 3 The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on a one -for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an ascribed issue price equal to the Base Redemption Value. 4 With the exception of Series A Preference Shares, after the redemption and conversion option dates, holders may elect to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/ 365 ) x 90 day Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q), 2.5% (Series S), 2.4% (Series 4), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7% (Series 16), 4.1% (Series 18) or 3.2% (Series 20); or US $25 x (number of days in quarter/ 365 ) x three -month United States Government treasury bill rate + 3.1% (Series K), 3.2% (Series M), 3.1% (Series 2) or 2.8% (Series 6). 5 The floating quarterly dividend amount for the Series C Preference Shares was decreased to $0.25395 from $0.25459 on March 1, 2019, was increased to $0.25647 from $0.25395 on June 1, 2019, was decreased to $0.25243 from $0.25647 on September 1, 2019 and was increased to $0.25305 from $0.25243 on December 1, 2019, due to reset on a quarterly basis following the issuance thereof. 6 No Series P, R, 3, 5, 7 or 9 Preference shares were converted on the March 1, 2019, June 1, 2019, September 1, 2019, March 1, 2019, March 1, 2019 or December 1, 2019 conversion option dates, respectively. However, the quarterly dividend amounts for Series P, R, 3, 5, 7 or 9, was increased to $0.27369 from $0.25000 on March 1, 2019, increased to $0.25456 from $0.25000 on June 1, 2019, decreased to $0.23356 from $0.25000 on September 1, 2019, increased to US $0.33625 from US $0.27500 on March 1, 2019, increased to $0.27806 from $0.27500 on March 1, 2019 and decreased to $0.25606 from $0.27500 on December 1, 2019, respectively, due to reset on every fifth anniversary thereafter. DIVIDEND REINVESTMENT AND SHARE PURCHASE PLAN On November 2, 2018, we announced the suspension of our DRIP, effective immediately. Prior to the announcement, our shareholders were able to participate in the DRIP, which enabled participants to reinvest their dividends in our common shares at a 2% discount to market price and to make additional optional cash payments to purchase common shares at the market price, free of brokerage or other charges. Refer to Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Dividends for details on dividends paid. SHAREHOLDER RIGHTS PLAN The Shareholder Rights Plan is designed to encourage the fair treatment of shareholders in connection with any takeover offer for us. Rights issued under the plan become exercisable when a person and any related parties acquires or announces its intention to acquire 20% or more of our outstanding common shares without complying with certain provisions set out in the plan or without approval of our Board of Directors. Should such an acquisition occur, each rights holder, other than the acquiring person and related parties, will have the right to purchase our common shares at a 50% discount to the market price at that time.

STOCK OPTION AND STOCK UNIT PLA

STOCK OPTION AND STOCK UNIT PLANS	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
STOCK OPTION AND STOCK UNIT PLANS	STOCK OPTION AND STOCK UNIT PLANS We maintain four long-term incentive compensation plans: the ISO Plan, the Performance Stock Options (PSO) Plan, the PSU Plan and the RSU Plan. In 2019, Enbridge adopted a new Long Term Incentive Plan with an effective date of February 13, 2019. The 2019 plan replaced several of Enbridge's prior incentive award plans and no additional awards were made or will be made under the prior plans as of the effective date. A reserve of 50 million was approved and established for the 2019 ISO Plan. Awards of PSUs and RUSs are notional units as if a unit was one Enbridge common share and are payable in cash. Prior to the Merger Transaction, Spectra Energy had a long-term incentive plan providing for the granting of stock options, restricted and unrestricted stock awards and units, and other equity-based awards. Upon closing of the Merger Transaction, Enbridge replaced existing Spectra Energy share-based payment awards with awards that will be settled in shares of Enbridge. Spectra Energy's cash-settled phantom awards were included in the fair value of the net assets acquired (Note 8) . Total stock-based compensation expense recorded for the years ended December 31, 2019 , 2018 and 2017 was $117 million , $106 million and $165 million , respectively. Disclosure of activity and assumptions for material stock-based compensation plans are included below. INCENTIVE STOCK OPTIONS Key employees are granted ISOs to purchase common shares at the market price on the grant date. ISOs vest in equal annual installments over a four -year period and expire 10 years after the issue date. December 31, 2019 Number Weighted Average Exercise Price Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (options in thousands; intrinsic value in millions of Canadian dollars) Options outstanding at beginning of year 34,387 43.47 Options granted 6,777 48.32 Options exercised 1 (4,519 ) 34.19 Options cancelled or expired (1,598 ) 50.62 Options outstanding at end of year 35,047 47.73 6.2 157 Options vested at end of year 2 20,581 47.67 4.7 92 1 The total intrinsic value of ISOs exercised during the years ended December 31, 2019 , 2018 and 2017 was $58 million , $42 million and $62 million , respectively, and cash received on exercise was $1 million , $15 million and $17 million , respectively. 2 The total fair value of ISOs vested during the years ended December 31, 2019 , 2018 and 2017 was $32 million , $36 million and $44 million , respectively. Weighted average assumptions used to determine the fair value of ISOs granted using the Black-Scholes-Merton option pricing model are as follows: Year ended December 31, 2019 2018 2017 Fair value per option (Canadian dollars) 1 4.37 3.86 6.00 Valuation assumptions Expected option term (years) 2 5 5 5 Expected volatility 3 19.9 % 21.9 % 20.4 % Expected dividend yield 4 6.1 % 6.4 % 4.4 % Risk-free interest rate 5 2.0 % 2.2 % 1.2 % 1 Options granted to United States employees are based on NYSE prices. The option value and assumptions shown are based on a weighted average of the United States and the Canadian options. The fair values per option for the years ended December 31, 2019 , 2018 and 2017 were $4.04 , $3.75 and $5.66 , respectively, for Canadian employees and US $4.09 , US $3.30 and US $5.72 , respectively, for United States employees. 2 The expected option term is six years based on historical exercise practice and three years for retirement eligible employees. 3 Expected volatility is determined with reference to historic daily share price volatility and consideration of the implied volatility observable in call option values near the grant date. 4 The expected dividend yield is the current annual dividend at the grant date divided by the current stock price. 5 The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields and the United States Treasury Bond Yields. Compensation expense recorded for the years ended December 31, 2019 , 2018 and 2017 for ISOs was $32 million , $28 million and $40 million , respectively. As at December 31, 2019 , unrecognized compensation expense related to non-vested stock-based compensation arrangements granted under the ISO Plan was $18 million . The expense is expected to be fully recognized over a weighted average period of approximately two years . PERFORMANCE STOCK UNITS Under PSU awards for certain key employees, cash awards are paid following a three-year performance cycle. Awards are calculated by multiplying the number of units outstanding at the end of the performance period by the Company's weighted average share price for 20 days prior to the maturity of the grant and by a performance multiplier. The performance multiplier ranges from zero , if our performance fails to meet threshold performance levels, to a maximum of two if we perform within the highest range of its performance targets. The performance multiplier is derived through a calculation of our Risk Adjusted Total Shareholder Return (in 2017) and Total Shareholder Return (commencing in 2018) percentile rank, in each case relative to a specified peer group of companies and our distributable cash flow, adjusted for unusual, non-operating or non-recurring items, relative to targets established at the time of grant. To calculate the 2019 expense, a multiplier of one was used for each of the 2017, 2018 and 2019 PSU grants. December 31, 2019 Number Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 1,069 Units granted 1,093 Units cancelled (65 ) Units matured 1 (25 ) Dividend reinvestment 117 Units outstanding at end of year 2,189 1.5 111 1 The total amount paid during the years ended December 31, 2019 , 2018 and 2017 for PSUs was $19 million , $18 million and $28 million , respectively. Compensation expense recorded for the years ended December 31, 2019 , 2018 and 2017 for PSUs was $40 million , $15 million and $5 million , respectively. As at December 31, 2019 , unrecognized compensation expense related to non-vested PSUs was $55 million . The expense is expected to be fully recognized over a weighted average period of approximately two years . RESTRICTED STOCK UNITS Under RSU awards, cash awards are paid to certain of our employees following a 35 -month maturity period. RSU holders receive cash equal to our weighted average share price for 20 days prior to the maturity of the grant multiplied by the units outstanding on the maturity date. December 31, 2019 Number Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 1,213 Units granted 1,087 Units cancelled (96 ) Units matured 1 (706 ) Dividend reinvestment 126 Units outstanding at end of year 1,624 1.6 82 1 The total amount paid during the years ended December 31, 2019 , 2018 and 2017 for RSUs was $34 million , $41 million and $39 million , respectively. Compensation expense recorded for the years ended December 31, 2019 , 2018 and 2017 for RSUs was $41 million , $32 million and $46 million , respectively. As at December 31, 2019 , unrecognized compensation expense related to non-vested RSUs was $47 million . The expense is expected to be fully recognized over a weighted average period of approximately two years .

COMPONENTS OF ACCUMULATED OTHER

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)	12 Months Ended
	Dec. 31, 2019
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)	COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) Changes in AOCI attributable to our common shareholders for the years ended December 31, 2019 , 2018 and 2017 are as follows: Cash Flow Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance at January 1, 2019 (770 ) (598 ) 4,323 34 (317 ) 2,672 Other comprehensive income/(loss) retained in AOCI (599 ) 320 (2,927 ) 34 (124 ) (3,296 ) Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 157 — — — — 157 Commodity contracts 2 (1 ) — — — — (1 ) Foreign exchange contracts 3 5 — — — — 5 Other contracts 4 (3 ) — — — — (3 ) Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 17 17 (441 ) 320 (2,927 ) 34 (107 ) (3,121 ) Tax impact Income tax on amounts retained in AOCI 169 (39 ) — 6 28 164 Income tax on amounts reclassified to earnings (31 ) — — — (4 ) (35 ) 138 (39 ) — 6 24 129 Other — — — (7 ) 55 48 Balance at December 31, 2019 (1,073 ) (317 ) 1,396 67 (345 ) (272 ) Cash Flow Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance at January 1, 2018 (644 ) (139 ) 77 10 (277 ) (973 ) Other comprehensive income/(loss) retained in AOCI (244 ) (509 ) 4,301 16 (85 ) 3,479 Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 157 — — — — 157 Commodity contracts 2 (1 ) — — — — (1 ) Foreign exchange contracts 3 7 — — — — 7 Other contracts 4 22 — — — — 22 Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 16 16 (59 ) (509 ) 4,301 16 (69 ) 3,680 Tax impact Income tax on amounts retained in AOCI 57 50 — 8 33 148 Income tax on amounts reclassified to earnings (37 ) — — — (4 ) (41 ) 20 50 — 8 29 107 Sponsored Vehicles buy-in 6 (87 ) — (55 ) — — (142 ) Balance at December 31, 2018 (770 ) (598 ) 4,323 34 (317 ) 2,672 Cash Flow Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance at January 1, 2017 (746 ) (629 ) 2,700 37 (304 ) 1,058 Other comprehensive income/(loss) retained in AOCI 1 478 (2,623 ) (11 ) 18 (2,137 ) Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 207 — — — — 207 Commodity contracts 2 (7 ) — — — — (7 ) Foreign exchange contracts 3 (6 ) — — — — (6 ) Other contracts 4 (6 ) — — — — (6 ) Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 41 41 189 478 (2,623 ) (11 ) 59 (1,908 ) Tax impact Income tax on amounts retained in AOCI (16 ) 12 — (16 ) (10 ) (30 ) Income tax on amounts reclassified to earnings (71 ) — — — (22 ) (93 ) (87 ) 12 — (16 ) (32 ) (123 ) Balance at December 31, 2017 (644 ) (139 ) 77 10 (277 ) (973 ) 1 Reported within Interest expense in the Consolidated Statements of Earnings. 2 Reported within Transportation and other services revenue, Commodity sales revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. 3 Reported within Transportation and other services revenues and Net foreign currency gain/(loss) in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. 5 These components are included in the computation of net benefit costs and are reported within Other income/(expense) in the Consolidated Statements of Earnings. 6 Represents the historical noncontrolling interests and redeemable noncontrolling interests related to the Sponsored Vehicles reclassified to AOCI, upon the completion of the buy-in.

RISK MANAGEMENT AND FINANCIAL I

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	RISK MANAGEMENT AND FINANCIAL INSTRUMENTS MARKET RISK Our earnings, cash flows and OCI are subject to movements in foreign exchange rates, interest rates, commodity prices and our share price (collectively, market risks). Formal risk management policies, processes and systems have been designed to mitigate these risks. The following summarizes the types of market risks to which we are exposed and the risk management instruments used to mitigate them. We use a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below. Foreign Exchange Risk We generate certain revenues, incur expenses and hold a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, our earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability. We employ financial derivative instruments to hedge foreign currency denominated earnings exposure. A combination of qualifying and non-qualifying derivative instruments is used to hedge anticipated foreign currency denominated revenues and expenses and to manage variability in cash flows. We hedge certain net investments in United States dollar denominated investments and subsidiaries using foreign currency derivatives and United States dollar denominated debt. Interest Rate Risk Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. We monitor our debt portfolio mix of fixed and variable rate debt instruments to manage a consolidated portfolio of floating rate debt within the Board of Directors approved policy limit of a maximum of 30% of floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk. Pay fixed-receive floating interest rate swaps may be used to hedge against the effect of future interest rate movements. We have implemented a program to significantly mitigate the impact of short-term interest rate volatility on interest expense via execution of floating to fixed interest rate swaps with an average swap rate of 2.9%. We are exposed to changes in the fair value of fixed rate debt that arise as a result of the changes in market interest rates. Pay floating-receive fixed interest rate swaps are used, when applicable, to hedge against future changes to the fair value of fixed rate debt which mitigates the impact of fluctuations in the fair value of fixed rate debt via execution of fixed to floating interest rate swaps. As at December 31, 2019 , we do not have any pay floating-receive fixed interest rate swaps outstanding. Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have established a program within some of our subsidiaries to mitigate our exposure to long-term interest rate variability on select forecast term debt issuances via execution of floating to fixed interest rate swaps with an average swap rate of 3%. Commodity Price Risk Our earnings and cash flows are exposed to changes in commodity prices as a result of our ownership interests in certain assets and investments, as well as through the activities of our energy services subsidiaries. These commodities include natural gas, crude oil, power and NGL. We employ financial and physical derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. We use primarily non-qualifying derivative instruments to manage commodity price risk. Equity Price Risk Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure to our own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. We use equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, restricted share units. We use a combination of qualifying and non-qualifying derivative instruments to manage equity price risk. TOTAL DERIVATIVE INSTRUMENTS The following table summarizes the Consolidated Statements of Financial Position location and carrying value of our derivative instruments. We generally have a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of our financial derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit events and reduce our credit risk exposure on financial derivative asset positions outstanding with the counterparties in those circumstances. The following table summarizes the maximum potential settlement amounts in the event of these specific circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position. The following table summarizes the maximum potential settlement amounts in the event of these specific circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position. December 31, 2019 Derivative Instruments Used as Cash Flow Hedges Derivative Instruments Used as Net Investment Hedges Non- Qualifying Derivative Instruments Total Gross Derivative Instruments as Presented Amounts Available for Offset Total Net Derivative Instruments (millions of Canadian dollars) Accounts receivable and other Foreign exchange contracts — — 161 161 (78 ) 83 Commodity contracts — — 163 163 (47 ) 116 Other contracts 1 — 3 4 — 4 1 — 327 328 1 (125 ) 203 Deferred amounts and other assets Foreign exchange contracts 10 — 71 81 (42 ) 39 Commodity contracts — — 17 17 (2 ) 15 Other contracts 2 — 1 3 — 3 12 — 89 101 (44 ) 57 Accounts payable and other Foreign exchange contracts (5 ) (13 ) (392 ) (410 ) 78 (332 ) Interest rate contracts (353 ) — — (353 ) — (353 ) Commodity contracts — — (173 ) (173 ) 47 (126 ) (358 ) (13 ) (565 ) (936 ) 2 125 (811 ) Other long-term liabilities Foreign exchange contracts — — (934 ) (934 ) 42 (892 ) Interest rate contracts (181 ) — — (181 ) — (181 ) Commodity contracts (5 ) — (60 ) (65 ) 2 (63 ) (186 ) — (994 ) (1,180 ) 44 (1,136 ) Total net derivative asset/(liability) Foreign exchange contracts 5 (13 ) (1,094 ) (1,102 ) — (1,102 ) Interest rate contracts (534 ) — — (534 ) — (534 ) Commodity contracts (5 ) — (53 ) (58 ) — (58 ) Other contracts 3 — 4 7 — 7 (531 ) (13 ) (1,143 ) (1,687 ) — (1,687 ) 1 Reported within Accounts receivable and other (2019 - $327 million ; 2018 - $498 million ) and Accounts receivable from affiliates (2019 - $1 million ; 2018 - nil ) on the Consolidated Statements of Financial Position. 2 Reported within Accounts payable and other (2019 - $920 million ; 2018 - $1,234 million ) and Accounts payable to affiliates (2019 - $16 million ; 2018 - nil ) on the Consolidated Statements of Financial Position. December 31, 2018 Derivative Derivative Non- Total Gross Amounts Total Net Derivative Instruments (millions of Canadian dollars) Accounts receivable and other Foreign exchange contracts — — 47 47 (37 ) 10 Interest rate contracts 22 — — 22 (2 ) 20 Commodity contracts 2 — 427 429 (114 ) 315 24 — 474 498 (153 ) 345 Deferred amounts and other assets Foreign exchange contracts 23 — 39 62 (39 ) 23 Interest rate contracts 5 — — 5 — 5 Commodity contracts 19 — 33 52 (21 ) 31 47 — 72 119 (60 ) 59 Accounts payable and other Foreign exchange contracts (5 ) — (610 ) (615 ) 37 (578 ) Interest rate contracts (163 ) — (178 ) (341 ) 2 (339 ) Commodity contracts — — (273 ) (273 ) 114 (159 ) Other contracts (1 ) — (4 ) (5 ) — (5 ) (169 ) — (1,065 ) (1,234 ) 153 (1,081 ) Other long-term liabilities Foreign exchange contracts (1 ) (15 ) (2,196 ) (2,212 ) 39 (2,173 ) Interest rate contracts (201 ) — — (201 ) — (201 ) Commodity contracts — — (178 ) (178 ) 21 (157 ) Other contracts (1 ) — (1 ) (2 ) — (2 ) (203 ) (15 ) (2,375 ) (2,593 ) 60 (2,533 ) Total net derivative asset/(liability) Foreign exchange contracts 17 (15 ) (2,720 ) (2,718 ) — (2,718 ) Interest rate contracts (337 ) — (178 ) (515 ) — (515 ) Commodity contracts 21 — 9 30 — 30 Other contracts (2 ) — (5 ) (7 ) — (7 ) (301 ) (15 ) (2,894 ) (3,210 ) — (3,210 ) The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments. 2019 2018 As at December 31, 2020 2021 2022 2023 2024 Thereafter Total Total Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars) 1,121 — — — — — 1,121 926 Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars) 5,631 4,946 5,182 1,804 1,856 — 19,419 19,075 Foreign exchange contracts - GBP forwards - sell (millions of GBP) 94 27 28 29 30 90 298 318 Foreign exchange contracts - Euro forwards - purchase (millions of Euro) — — — — — — — 226 Foreign exchange contracts - Euro forwards - sell (millions of Euro) 23 94 94 92 91 515 909 909 Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen) — — 72,500 — — — 72,500 52,662 Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars) 6,090 4,090 400 48 35 121 10,784 19,664 Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars) 3,533 1,569 — — — — 5,102 8,558 Equity contracts (millions of Canadian dollars) 20 34 — — — — 54 55 Commodity contracts - natural gas (billions of cubic feet) (33 ) 14 15 3 — — (1 ) (167 ) Commodity contracts - crude oil (millions of barrels) 28 — — — — — 28 4 Commodity contracts - NGL (millions of barrels) 2 — — — — — 2 — Commodity contracts - power (megawatt per hour (MW/H) 80 (3 ) (43 ) (43 ) (43 ) (43 ) 1 (16 ) 2 (7 ) 2 1 As at December 31, 2019 , thereafter includes an average net purchase/(sell) of power of (43) MW/H for 2025. 2 Total is an average net purchase/(sell) of power. The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income The following table presents the effect of cash flow hedges and net investment hedges on our consolidated earnings and consolidated comprehensive income, before the effect of income taxes: 2019 2018 2017 (millions of Canadian dollars) Amount of unrealized gain/(loss) recognized in OCI Cash flow hedges Foreign exchange contracts (19 ) 19 (5 ) Interest rate contracts (559 ) (190 ) 6 Commodity contracts (25 ) 2 11 Other contracts 10 (3 ) 1 Net investment hedges Foreign exchange contracts 2 31 284 (591 ) (141 ) 297 Amount of (gain)/loss reclassified from AOCI to earnings Foreign exchange contracts 1 5 5 (104 ) Interest rate contracts 2,3 157 184 384 Commodity contracts 4 (1 ) (1 ) (9 ) Other contracts 5 (3 ) 3 8 158 191 279 1 Reported within Transportation and other services revenues and Net foreign currency gain/(loss) in the Consolidated Statements of Earnings. 2 Reported within Interest expense in the Consolidated Statements of Earnings. Effective January 1, 2019, hedge ineffectiveness will no longer be measured or recorded. See Note 2. 3 For the year ended December 31, 2017, includes settlements of $296 million loss related to the termination of long-term interest rate swaps as not highly probable to issue long-term debt. 4 Reported within Transportation and other services revenue, Commodity sales revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. 5 Reported within Operating and administrative expenses in the Consolidated Statements of Earnings. We estimate that a loss of $80 million from AOCI related to cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows is 24 months as at December 31, 2019 . Fair Value Derivatives For interest rate derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk is included in Interest expense in the Consolidated Statements of Earnings. Year ended December 31, 2019 2018 (millions of Canadian dollars) Unrealized gain on derivative — 7 Unrealized gain on hedged item — 1 Realized loss on derivative — (8 ) Realized loss on hedged item — (1 ) Non-Qualifying Derivatives The following table presents the unrealized gains and losses associated with changes in the fair value of our non-qualifying derivatives: Year ended December 31, 2019 2018 2017 (millions of Canadian dollars) Foreign exchange contracts 1 1,626 (1,390 ) 1,284 Interest rate contracts 2 178 5 157 Commodity contracts 3 (62 ) 485 (199 ) Other contracts 4 9 (3 ) — Total unrealized derivative fair value gain/(loss), net 1,751 (903 ) 1,242 1 For the respective annual periods, reported within Transportation and other services revenue ( 2019 - $930 million gain; 2018 - $1,108 million loss; 2017 - $800 million gain) and Net foreign currency gain/(loss) ( 2019 - $696 million gain; 2018 - $282 million loss; 2017 - $484 million gain) in the Consolidated Statements of Earnings. 2 Reported as a decrease within Interest expense in the Consolidated Statements of Earnings. 3 For the respective annual periods, reported within Transportation and other services revenue ( 2019 - $26 million loss; 2018 - $66 million gain; 2017 - $104 million loss), Commodity sales ( 2019 - $544 million loss; 2018 - $599 million gain; 2017 - $90 million gain), Commodity costs ( 2019 - $459 million gain; 2018 - $193 million loss; 2017 - $223 million loss) and Operating and administrative expense ( 2019 - $49 million gain; 2018 - $13 million gain; 2017 - $38 million gain) in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. LIQUIDITY RISK Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a 12 - month rolling time period to determine whether sufficient funds will be available and maintain substantial capacity under our committed bank lines of credit to address any contingencies. Our primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium-term notes. We also maintain current shelf prospectuses with securities regulators which enables ready access to either the Canadian or United States public capital markets, subject to market conditions. In addition, we maintain sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated requirements for approximately one year without accessing the capital markets. We are in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at December 31, 2019 . As a result, all credit facilities are available to us and the banks are obligated to fund and have been funding us under the terms of the facilities. CREDIT RISK Entering into derivative instruments may result in exposure to credit risk from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk management transactions primarily with institutions that possess strong investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated through maintenance and monitoring of credit exposure limits and contractual requirements, netting arrangements, and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools. We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments: December 31, 2019 2018 (millions of Canadian dollars) Canadian financial institutions 146 28 United States financial institutions 40 107 European financial institutions 3 84 Asian financial institutions 92 6 Other 1 113 337 394 562 1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties. As at December 31, 2019 , we provided letters of credit totaling nil in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant International Swaps and Derivatives Association agreements. We held no cash collateral on derivative asset exposures as at December 31, 2019 and December 31, 2018 . Gross derivative balances have been presented without the effects of collateral posted. Derivative assets are adjusted for non-performance risk of our counterparties using their credit default swap spread rates, and are reflected at fair value. For derivative liabilities, our non-performance risk is considered in the valuation. Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, assessment of credit ratings and netting arrangements. Within Enbridge Gas, credit risk is mitigated by the utilities' large and diversified customer base and the ability to recover an estimate for doubtful accounts through the ratemaking process. We actively monitor the financial strength of large industrial customers and, in select cases, have obtained additional security to minimize the risk of default on receivables. Generally, we classify and provide for receivables older than 30 days as past due. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value. FAIR VALUE MEASUREMENTS Our financial assets and liabilities measured at fair value on a recurring basis include derivative instruments. We also disclose the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects our best estimates of market value based on generally accepted valuation techniques or models and is supported by observable market prices and rates. When such values are not available, we use discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value. FAIR VALUE OF FINANCIAL INSTRUMENTS We categorize our derivative instruments measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 Level 1 includes derivatives measured at fair value based on unadjusted quoted prices for identical assets and liabilities in active markets that are accessible at the measurement date. An active market for a derivative is considered to be a market where transactions occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 instruments consist primarily of exchange traded derivatives used to mitigate the risk of crude oil price fluctuations. Level 2 Level 2 includes derivative valuations determined using directly or indirectly observable inputs other than quoted prices included within Level 1. Derivatives in this category are valued using models or other industry standard valuation techniques derived from observable market data. Such valuation techniques include inputs such as quoted forward prices, time value, volatility factors and broker quotes that can be observed or corroborated in the market for the entire duration of the derivative. Derivatives valued using Level 2 inputs include non-exchange traded derivatives such as over-the-counter foreign exchange forward and cross currency swap contracts, interest rate swaps, physical forward commodity contracts, as well as commodity swaps and options for which observable inputs can be obtained. We have also categorized the fair value of our held to maturity preferred share investment and long-term debt as Level 2. The fair value of our held to maturity preferred share investment is primarily based on the yield of certain Government of Canada bonds. The fair value of our long-term debt is based on quoted market prices for instruments of similar yield, credit risk and tenor. Level 3 Level 3 includes derivative valuations based on inputs which are less observable, unavailable or where the observable data does not support a significant portion of the derivatives’ fair value. Generally, Level 3 derivatives are longer dated transactions, occur in less active markets, occur at locations where pricing information is not available or have no binding broker quote to support Level 2 classification. We have developed methodologies, benchmarked against industry standards, to determine fair value for these derivatives based on extrapolation of observable future prices and rates. Derivatives valued using Level 3 inputs primarily include long-dated derivative power contracts and NGL and natural gas contracts, basis swaps, commodity swaps, power and energy swaps, as well as options. We do not have any other financial instruments categorized in Level 3. We use the most observable inputs available to estimate the fair value of our derivatives. When possible, we estimate the fair value of our derivatives based on quoted market prices. If quoted market prices are not available, we use estimates from third party brokers. For non-exchange traded derivatives classified in Levels 2 and 3, we use standard valuation techniques to calculate the estimated fair value. These methods include discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models for options. Depending on the type of derivative and nature of the underlying risk, we use observable market prices (interest, foreign exchange, commodity and share price) and volatility as primary inputs to these valuation techniques. Finally, we consider our own credit default swap spread as well as the credit default swap spreads associated with our counterparties in our estimation of fair value. We have categorized our derivative assets and liabilities measured at fair value as follows: December 31, 2019 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 161 — 161 Commodity contracts — 33 130 163 Other contracts — 4 — 4 — 198 130 328 Long-term derivative assets Foreign exchange contracts — 81 — 81 Commodity contracts — 12 5 17 Other contracts — 3 — 3 — 96 5 101 Financial liabilities Current derivative liabilities Foreign exchange contracts — (410 ) — (410 ) Interest rate contracts — (353 ) — (353 ) Commodity contracts (5 ) (23 ) (145 ) (173 ) Other contracts — — — — (5 ) (786 ) (145 ) (936 ) Long-term derivative liabilities Foreign exchange contracts — (934 ) — (934 ) Interest rate contracts — (181 ) — (181 ) Commodity contracts — (6 ) (59 ) (65 ) Other contracts — — — — — (1,121 ) (59 ) (1,180 ) Total net financial asset/(liability) Foreign exchange contracts — (1,102 ) — (1,102 ) Interest rate contracts — (534 ) — (534 ) Commodity contracts (5 ) 16 (69 ) (58 ) Other contracts — 7 — 7 (5 ) (1,613 ) (69 ) (1,687 ) December 31, 2018 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 47 — 47 Interest rate contracts — 22 — 22 Commodity contracts 24 45 360 429 24 114 360 498 Long-term derivative assets Foreign exchange contracts — 62 — 62 Interest rate contracts — 5 — 5 Commodity contracts — 30 22 52 — 97 22 119 Financial liabilities Current derivative liabilities Foreign exchange contracts — (615 ) — (615 ) Interest rate contracts — (341 ) — (341 ) Commodity contracts (7 ) (28 ) (238 ) (273 ) Other contracts — (5 ) — (5 ) (7 ) (989 ) (238 ) (1,234 ) Long-term derivative liabilities Foreign exchange contracts — (2,212 ) — (2,212 ) Interest rate contracts — (201 ) — (201 ) Commodity contracts — (23 ) (155 ) (178 ) Other contracts — (2 ) — (2 ) — (2,438 ) (155 ) (2,593 ) Total net financial asset/(liability) Foreign exchange contracts — (2,718 ) — (2,718 ) Interest rate contracts — (515 ) — (515 ) Commodity contracts 17 24 (11 ) 30 Other contracts — (7 ) — (7 ) 17 (3,216 ) (11 ) (3,210 ) The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows: December 31, 2019 Fair Value Unobservable Input Minimum Price/Volatility Maximum Price/Volatility Weighted Average Price/Volatility Unit of Measurement (fair value in millions of Canadian dollars) Commodity contracts - financial 1 Natural gas — Forward gas price 1.95 4.88 3.04 $/mmbtu 2 Crude 4 Forward crude price 44.24 82.29 52.76 $/barrel NGL 3 Forward NGL price 0.54 0.86 0.82 $/gallon Power (61 ) Forward power price 27.84 71.79 57.46 $/MW/H Commodity contracts - physical 1 Natural gas 28 Forward gas price 1.00 8.37 2.53 $/mmbtu 2 Crude (45 ) Forward crude price 40.20 90.75 70.27 $/barrel NGL 2 Forward NGL price 0.18 2.01 0.79 $/gallon (69 ) 1 Financial and physical forward commodity contracts are valued using a market approach valuation technique. 2 One million British thermal units (mmbtu). If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on the fair value of our Level 3 derivative instruments. The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments include forward commodity prices, and for option contracts, price volatility. Changes in forward commodity prices could result in significantly different fair values for our Level 3 derivatives. Changes in price volatility would change the value of the option contracts. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of price volatility. Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows: Year ended December 31, 2019 2018 (millions of Canadian dollars) Level 3 net derivative liability at beginning of period (11 ) (387 ) Total gain/(loss) Included in earnings 1 27 206 Included in OCI (25 ) 2 Settlements (60 ) 168 Level 3 net derivative liability at end of period (69 ) (11 ) 1 Reported within Transportation and other services revenue, Commodity costs and Operating and administrative expenses in the Consolidated Statements of Earnings. Our policy is to recognize transfers as at the last day of the reporting period. There were no transfers between levels as at December 31, 2019 or 2018 . FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS Our other long-term investments in other entities with no actively quoted prices are classified as Fair Value Measurement Alternative (FVMA) investments and are recorded at cost less impairment. The carrying value of FVMA and other long-term investments totaled $ 99 million and $102 million as at December 31, 2019 and 2018 , respectively. We have Restricted long-term investments held in trust totaling $434 million and $323 million as at December 31, 2019 and 2018 , respectively, which are recognized at fair value. We have a held to maturity preferred share investment carried at its amortized cost of $580 million and $478 million as at December 31, 2019 and 2018 , respectively. These preferred shares are entitled to a cumulative preferred dividend based on the yield of 10 -year Government of Canada bonds plus a margin of 4.38% . The fair value of this preferred share investment approximates its face value of $580 million as at December 31, 2019 and 2018 . As at December 31, 2019 and 2018 , our long-term debt had a carrying value of $64.4 billion and $63.9 billion , respectively, before debt issuance costs and a fair value of $70.5 billion and $64.4 billion , respectively. We also have non-current notes receivable carried at book value and recorded in Deferred amounts and other assets in the Consolidated Statements of Financial Position. As at December 31, 2019 and 2018 , the non-current notes receivable had a carrying value of $1,026 million and $767 million , respectively, which also approximates their fair value. The fair value of other financial assets and liabilities other than derivative instruments, other long-term investments, restricted long-term investments and long-term debt approximate their cost due to the short period to maturity. NET INVESTMENT HEDGES We have designated a portion of our United States dollar denominated debt, as well as a portfolio of foreign exchange forward contracts, as a hedge of our net investment in United States dollar denominated investments and subsidiaries. During the years ended December 31, 2019 and 2018 , we recognized an unrealized foreign exchange gain of $317 million and a loss of $479 million , respectively, on the translation of United States dollar denominated debt and an unrealized gain on the change in fair value of our outstanding foreign exchange forward contracts of $2 million and $30 million , respectively, in OCI. During the years ended December 31, 2019 and 2018 , we recognized a realized loss of nil and $45 million , respectively, in OCI associated with the settlement of foreign exchange forward contracts and also recognized a realized loss of nil and loss of $14 million , respectively, in OCI associated with the settlement of United States dollar denominated debt that had matured during the period.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES INCOME TAX RATE RECONCILIATION Year ended December 31, 2019 2018 2017 (millions of Canadian dollars) Earnings before income taxes 7,535 3,570 569 Canadian federal statutory income tax rate 15 % 15 % 15 % Expected federal taxes at statutory rate 1,130 536 85 Increase/(decrease) resulting from: Provincial and state income taxes 1 415 (24 ) 133 Foreign and other statutory rate differentials 129 94 (601 ) Impact of United States tax reform 2 — (2 ) (2,045 ) Effects of rate-regulated accounting 3 (63 ) (163 ) (189 ) Foreign allowable interest deductions 4 (29 ) (134 ) (124 ) Part VI.1 tax, net of federal Part I deduction 5 78 76 68 Impairment of goodwill — 192 15 United States BEAT tax 67 43 — Non-taxable portion of gain/(loss) on sale of investment to unrelated party 6 — 31 — Valuation allowance 7 26 (172 ) (17 ) Intercorporate investments 8 (14 ) (149 ) 77 Noncontrolling interests (13 ) (47 ) (80 ) Other (18 ) (44 ) (19 ) Income tax (recovery)/expense 1,708 237 (2,697 ) Effective income tax rate 22.7 % 6.6 % (474.0 )% 1 The change in provincial and state income taxes from 2018 to 2019 reflects the increase in earnings from operations and the impact of state tax rate changes in both the United States and Canada. 2 The amount was related to the enactment of the Tax Cuts and Jobs Act (TCJA) by the United States on December 22, 2017, which included a reduction in the federal corporate income tax rate from 35% to 21% effective for taxation years beginning after December 31, 2017. 3 The amount in 2019 included the federal component of the tax effect of the write-off of regulatory assets (Note 7) . 4 The decrease in foreign allowable interest deductions in 2019 was due to changes in the related loan portfolio and tax legislative changes in Canada, the United States, and Europe. 5 Part VI.1 tax is a tax levied on preferred share dividends paid in Canada. 6 The amount represents the federal component of the non-taxable portion of the gain on the sales of the Canadian Natural Gas Gathering and Processing Businesses in 2018. 7 The increase in 2018 is due to the federal component of the tax effect of a valuation allowance on the deferred tax assets related to an outside basis temporary difference that, in 2018, was more likely than not to be realized. 8 The amount relates to the federal component of changes in assertions regarding the manner of recovery of intercorporate investments such that deferred tax related to outside basis temporary differences was required to be recorded for MATL (Note 8), Renewable Assets in 2018 and for EIPLP in 2017. COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES Year ended December 31, 2019 2018 2017 (millions of Canadian dollars) Earnings/(loss) before income taxes Canada 3,560 118 2,200 United States 3,115 2,582 (2,431 ) Other 860 870 800 7,535 3,570 569 Current income taxes Canada 347 311 129 United States 107 66 46 Other 98 8 5 552 385 180 Deferred income taxes Canada 490 (598 ) 299 United States 672 439 (3,160 ) Other (6 ) 11 (16 ) 1,156 (148 ) (2,877 ) Income tax (recovery)/expense 1,708 237 (2,697 ) COMPONENTS OF DEFERRED INCOME TAXES Deferred tax assets and liabilities are recognized for the future tax consequences of differences between carrying amounts of assets and liabilities and their respective tax bases. Major components of deferred income tax assets and liabilities are as follows: December 31, 2019 2018 (millions of Canadian dollars) Deferred income tax liabilities Property, plant and equipment (7,290 ) (7,018 ) Investments (4,620 ) (4,441 ) Regulatory assets (1,052 ) (756 ) Other (40 ) (192 ) Total deferred income tax liabilities (13,002 ) (12,407 ) Deferred income tax assets Financial instruments 679 1,103 Pension and OPEB plans 206 181 Loss carryforwards 1,693 1,820 Other 1,641 1,274 Total deferred income tax assets 4,219 4,378 Less valuation allowance (84 ) (51 ) Total deferred income tax assets, net 4,135 4,327 Net deferred income tax liabilities (8,867 ) (8,080 ) Presented as follows: Total deferred income tax assets 1,000 1,374 Total deferred income tax liabilities (9,867 ) (9,454 ) Net deferred income tax liabilities (8,867 ) (8,080 ) A valuation allowance has been established for certain loss and credit carryforwards, and outside basis temporary differences on investments that reduce deferred income tax assets to an amount that will more likely than not be realized. As at December 31, 2019 and 2018 , we recognized the benefit of unused tax loss carryforwards of $3.2 billion and $3.4 billion , respectively, in Canada which expire in 2026 and beyond. As at December 31, 2019 and 2018 , we recognized the benefit of unused tax loss carryforwards of $3.6 billion and $3.4 billion , respectively, in the United States which expire in 2023 and beyond. We have not provided for deferred income taxes on the difference between the carrying value of substantially all of our foreign subsidiaries and their corresponding tax basis as the earnings of those subsidiaries are intended to be permanently reinvested in their operations. As such these investments are not anticipated to give rise to income taxes in the foreseeable future. The difference between the carrying values of the investments and their tax bases is largely a result of unremitted earnings and currency translation adjustments. The unremitted earnings and currency translation adjustment for which no deferred taxes have been recognized in respect of foreign subsidiaries were $5.3 billion and $5.8 billion for the period December 31, 2019 and 2018 , respectively. If such earnings are remitted, in the form of dividends or otherwise, we may be subject to income taxes and foreign withholding taxes. The determination of the amount of unrecognized deferred income tax liabilities on such amounts is not practicable. Enbridge and certain of our subsidiaries are subject to taxation in Canada, the United States and other foreign jurisdictions. The material jurisdictions in which we are subject to potential examinations include the United States (Federal) and Canada (Federal, Alberta and Ontario). We are open to examination by Canadian tax authorities for the 2010 to 2019 tax years and by United States tax authorities for the 2015 to 2019 tax years. We are currently under examination for income tax matters in Canada for the 2013 to 2017 tax years. We are not currently under examination for income tax matters in any other material jurisdiction where we are subject to income tax. United States Tax Reform On December 22, 2017, the United States enacted the TCJA. As a result of the TCJA we recorded $67 million and $43 million in tax expense for the years ended December 31, 2019 and 2018, respectively in connection with the Base erosion and Anti-abuse tax (BEAT). We recorded no provisions for the Global Intangible Low Taxed Income Tax (GILTI). Most changes to the TCJA are effective for taxation years beginning after December 31, 2017. While the changes are broad and complex, the most significant change was the reduction in the corporate federal income tax rate from 35% to 21% . In 2017 we were also impacted by a one-time deemed repatriation or “toll” tax on undistributed earnings and profits of United States controlled foreign affiliates, including Canadian subsidiaries. During the first quarter of 2018 we refined our calculation of the regulatory liability associated with the TCJA which resulted in a $30 million reduction to the overall regulatory liability. An additional reduction to the regulated liability in the amount of $223 million was recorded in the fourth quarter of 2018 in connection with rate cases filed that eliminated a portion of regulated liability formerly included in SEP's rate base. In 2017 we made reasonable estimates for the measurement and accounting of certain effects of the TCJA in accordance with SEC Staff Accounting Bulletin No.118 (SAB 118). Accordingly, we recorded a $34 million increase to our 2017 current income tax provision related to the toll tax, payable over eight years. We recorded a $2.0 billion decrease to our 2017 deferred income tax provision related to the reduction in the corporate federal income tax rate. The accounting for these items decreased our accumulated deferred income tax liability by $3.1 billion and increased our regulatory liability by $1.1 billion in 2017. We have also adjusted our valuation allowance for certain deferred tax assets existing at December 31, 2016 for the reduction in the corporate federal income tax rate by $0.2 billion . We have recognized these tax impacts and included these amounts in our consolidated financial statements for the year ended December 31, 2017. UNRECOGNIZED TAX BENEFITS Year ended December 31, 2019 2018 (millions of Canadian dollars) Unrecognized tax benefits at beginning of year 139 150 Gross increases for tax positions of current year 1 2 Gross decreases for tax positions of prior year (1 ) (12 ) Change in translation of foreign currency (4 ) 3 Lapses of statute of limitations (6 ) (3 ) Settlements — (1 ) Unrecognized tax benefits at end of year 129 139 The unrecognized tax benefits as at December 31, 2019 , if recognized, would impact our effective income tax rate. We do not anticipate further adjustments to the unrecognized tax benefits during the next 12 months that would have a material impact on our consolidated financial statements. We recognize accrued interest and penalties related to unrecognized tax benefits as a component of income taxes. Income taxes for the years ended December 31, 2019 and 2018 were $3 million expense and $5 million expense, respectively, of interest and penalties. As at December 31, 2019 and 2018 , interest and penalties of $15 million and $12 million , respectively, have been accrued.

PENSION AND OTHER POSTRETIREMEN

PENSION AND OTHER POSTRETIREMENT BENEFITS	12 Months Ended
	Dec. 31, 2019
Retirement Benefits [Abstract]
PENSION AND OTHER POSTRETIREMENT BENEFITS	PENSION AND OTHER POSTRETIREMENT BENEFITS PENSION PLANS We sponsor Canadian and United States contributory and non-contributory registered defined benefit and defined contribution pension plans, which provide benefits covering substantially all employees. The Canadian Plans provide defined benefit and defined contribution pension benefits to our Canadian employees. The United States Plans provide defined benefit pension benefits to our United States employees. We also sponsor supplemental non-contributory defined benefit pension plans, which provide non-registered benefits for certain employees in Canada and the United States. Defined Benefit Pension Plan Benefits Benefits payable from the defined benefit pension plans are based on each plan participant’s years of service and final average remuneration. Some benefits are partially inflation-indexed after a plan participant’s retirement. Our contributions are made in accordance with independent actuarial valuations. Participant contributions to contributory defined benefit pension plans are based upon each plan participant’s current eligible remuneration. Defined Contribution Pension Plan Benefits Our contributions are based on each plan participant’s current eligible remuneration. Our contributions for some defined contribution pension plans are also based on age and years of service. Our defined contribution pension benefit costs are equal to the amount of contributions required to be made by us. Benefit Obligations, Plan Assets and Funded Status The following table details the changes in the projected benefit obligation, the fair value of plan assets and the recorded assets or liabilities for our defined benefit pension plans: Canada United States December 31, 2019 2018 2019 2018 (millions of Canadian dollars) Change in projected benefit obligation Projected benefit obligation at beginning of year 3,997 4,033 1,214 1,279 Service cost 149 149 45 45 Interest cost 139 130 41 38 Participant contributions 32 25 — — Actuarial (gain)/loss 423 (146 ) 106 (103 ) Benefits paid (187 ) (184 ) (101 ) (60 ) Plan settlements 1 (99 ) — (1 ) (65 ) Transfers out (8 ) (10 ) (6 ) — Foreign currency exchange rate changes — — (63 ) 105 Other — — (5 ) (25 ) Projected benefit obligation at end of year 2 4,446 3,997 1,230 1,214 Change in plan assets Fair value of plan assets at beginning of year 3,523 3,619 1,045 1,097 Actual return/(loss) on plan assets 448 (42 ) 176 (48 ) Employer contributions 114 113 46 40 Participant contributions 32 25 — — Benefits paid (187 ) (184 ) (101 ) (60 ) Plan settlements 1 (99 ) — (1 ) (65 ) Transfers out (4 ) (8 ) — — Foreign currency exchange rate changes — — (56 ) 91 Other — — (5 ) (10 ) Fair value of plan assets at end of year 3 3,827 3,523 1,104 1,045 Underfunded status at end of year (619 ) (474 ) (126 ) (169 ) Presented as follows: Deferred amounts and other assets 35 29 — — Accounts payable and other (9 ) (9 ) (4 ) (4 ) Other long-term liabilities (645 ) (494 ) (122 ) (165 ) (619 ) (474 ) (126 ) (169 ) 1 Plan settlements for the Canadian Plans are related to the disposition of our federally regulated BC Field Services business. 2 The accumulated benefit obligation for our Canadian pension plans was $4.0 billion and $3.7 billion as at December 31, 2019 and 2018 , respectively. The accumulated benefit obligation for our United States pension plans was $1.2 billion as at December 31, 2019 and 2018 . 3 Assets in the amount of $ 10 million ( 2018 - $ 7 million ) and $ 51 million ( 2018 - $ 39 million ), related to our Canadian and United States non-registered supplemental pension plan obligations, are held in Grantor Trusts and Rabbi Trusts that, in accordance with federal tax regulations, are not restricted from creditors. These assets are committed for the future settlement of benefit obligations included in the underfunded status as at the end of the year, however they are excluded from plan assets for accounting purposes. Certain of our pension plans have an accumulated benefit obligation in excess of the fair value of plan assets. For these plans, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets were as follows: Canada United States December 31, 2019 2018 2019 2018 (millions of Canadian dollars) Projected benefit obligation 1,481 1,422 103 1,214 Accumulated benefit obligation 1,361 1,299 98 1,179 Fair value of plan assets 1,087 1,064 — 1,045 Amount Recognized in Accumulated Other Comprehensive Income The amount of pre-tax AOCI relating to our pension plans are as follows: Canada United States December 31, 2019 2018 2019 2018 (millions of Canadian dollars) Net actuarial loss 445 435 134 133 Prior service credit — — (2 ) (3 ) Total amount recognized in AOCI 1 445 435 132 130 1 Excludes amounts related to cumulative translation adjustment. Net Periodic Benefit Cost and Other Amounts Recognized in Comprehensive Income The components of net periodic benefit cost and other amounts recognized in pre-tax Comprehensive income related to our pension plans are as follows: Canada United States Year ended December 31, 2019 2018 2017 2019 2018 2017 (millions of Canadian dollars) Service cost 149 149 156 45 45 48 Interest cost 139 130 116 41 38 35 Expected return on plan assets (245 ) (245 ) (201 ) (78 ) (88 ) (57 ) Amortization/settlement of net actuarial loss 41 25 29 2 7 10 Amortization/curtailment of prior service (credit)/cost — — — (1 ) 3 — Net periodic benefit cost 84 59 100 9 5 36 Defined contribution benefit cost 8 11 11 — — — Net pension cost recognized in Earnings 92 70 111 9 5 36 Amount recognized in OCI: Effect of plan combination — — — (6 ) — — Amortization/settlement of net actuarial loss (26 ) (11 ) (14 ) (2 ) (7 ) (9 ) Amortization/curtailment of prior service credit/(cost) — — — 1 (3 ) — Net actuarial loss arising during the year 115 112 38 8 28 — Total amount recognized in OCI 89 101 24 1 18 (9 ) Total amount recognized in Comprehensive income 181 171 135 10 23 27 We estimate that approximately $21 million related to the Canadian pension plans and nil related to the United States pension plans as at December 31, 2019 will be reclassified from AOCI into Earnings in the next 12 months. Actuarial Assumptions The weighted average assumptions made in the measurement of the projected benefit obligation and net periodic benefit cost of our pension plans are as follows: Canada United States 2019 2018 2017 2019 2018 2017 Projected benefit obligation Discount rate 3.0 % 3.8 % 3.6 % 3.0 % 3.9 % 3.5 % Rate of salary increase 3.2 % 3.2 % 3.2 % 2.9 % 2.8 % 3.1 % Net periodic benefit cost Discount rate 3.8 % 3.6 % 4.0 % 3.9 % 3.4 % 4.0 % Expected rate of return on plan assets 7.0 % 6.8 % 6.5 % 8.0 % 7.4 % 7.2 % Rate of salary increase 3.2 % 3.2 % 3.7 % 2.9 % 2.9 % 3.3 % OTHER POSTRETIREMENT BENEFIT PLANS We sponsor funded and unfunded defined benefit OPEB Plans, which provide non-contributory supplemental health, dental, life and health spending account benefit coverage for certain qualifying retired employees. Benefit Obligations, Plan Assets and Funded Status The following table details the changes in the accumulated postretirement benefit obligation, the fair value of plan assets and the recorded assets or liabilities for our defined benefit OPEB plans: Canada United States December 31, 2019 2018 2019 2018 (millions of Canadian dollars) Change in accumulated postretirement benefit obligation Accumulated postretirement benefit obligation at beginning of year 282 321 305 337 Service cost 5 8 2 3 Interest cost 10 10 10 10 Participant contributions — — 5 6 Actuarial (gain)/loss 15 (45 ) 7 (25 ) Benefits paid (6 ) (11 ) (28 ) (29 ) Plan amendments — — — (8 ) Foreign currency exchange rate changes — — (15 ) 27 Other (13 ) (1 ) 2 (16 ) Accumulated postretirement benefit obligation at end of year 293 282 288 305 Change in plan assets Fair value of plan assets at beginning of year — — 181 213 Actual return/(loss) on plan assets — — 27 (13 ) Employer contributions 6 11 10 8 Participant contributions — — 5 6 Benefits paid (6 ) (11 ) (28 ) (29 ) Foreign currency exchange rate changes — — (9 ) 16 Other — — 2 (20 ) Fair value of plan assets at end of year — — 188 181 Underfunded status at end of year (293 ) (282 ) (100 ) (124 ) Presented as follows: Deferred amounts and other assets — — — 2 Accounts payable and other (12 ) (12 ) (8 ) (7 ) Other long-term liabilities (281 ) (270 ) (92 ) (119 ) (293 ) (282 ) (100 ) (124 ) Amount Recognized in Accumulated Other Comprehensive Income The amount of pre-tax AOCI relating to our OPEB plans are as follows: Canada United States December 31, 2019 2018 2019 2018 (millions of Canadian dollars) Net actuarial gain (7 ) (29 ) (23 ) (15 ) Prior service credit (1 ) (2 ) (13 ) (15 ) Total amount recognized in AOCI 1 (8 ) (31 ) (36 ) (30 ) 1 Excludes amounts related to cumulative translation adjustment. Net Periodic Benefit Cost and Other Amounts Recognized in Comprehensive Income The components of net periodic benefit cost and other amounts recognized in pre-tax Comprehensive income related to our OPEB plans are as follows: Canada United States Year ended December 31, 2019 2018 2017 2019 2018 2017 (millions of Canadian dollars) Service cost 5 8 7 2 3 5 Interest cost 10 10 10 10 10 10 Expected return on plan assets — — — (12 ) (12 ) (10 ) Amortization/settlement of net actuarial gain (7 ) — — — (1 ) — Amortization/curtailment of prior service (credit)/cost (1 ) — 1 (2 ) (4 ) — Net periodic benefit cost recognized in Earnings 7 18 18 (2 ) (4 ) 5 Amount recognized in OCI: Amortization/settlement of net actuarial gain/(loss) 7 — (1 ) — 1 1 Amortization/curtailment of prior service credit 1 — — 2 4 — Net actuarial (gain)/loss arising during the year 15 (46 ) (8 ) (8 ) (1 ) (42 ) Prior service (credit)/cost — — (3 ) — (8 ) 1 Total amount recognized in OCI 23 (46 ) (12 ) (6 ) (4 ) (40 ) Total amount recognized in Comprehensive income 30 (28 ) 6 (8 ) (8 ) (35 ) We estimate that approximately $1 million related to the Canadian OPEB plans and $3 million related to the United States OPEB plans as at December 31, 2019 will be reclassified from AOCI into earnings in the next 12 months. Actuarial Assumptions The weighted average assumptions made in the measurement of the accumulated postretirement benefit obligation and net periodic benefit cost of our OPEB plans are as follows: Canada United States 2019 2018 2017 2019 2018 2017 Accumulated postretirement benefit obligation Discount rate 3.1 % 3.8 % 3.6 % 2.8 % 4.0 % 3.5 % Net periodic benefit cost Discount rate 3.8 % 3.6 % 4.0 % 4.0 % 3.3 % 4.0 % Rate of return on plan assets N/A N/A N/A 6.7 % 5.7 % 6.0 % Assumed Health Care Cost Trend Rates The assumed rates for the next year used to measure the expected cost of benefits are as follows: Canada United States 2019 2018 2019 2018 Health care cost trend rate assumed for next year 4.0 % 5.6 % 7.2 % 7.4 % Rate to which the cost trend is assumed to decline (ultimate trend rate) 4.0 % 4.4 % 4.5 % 4.5 % Year that the rate reaches the ultimate trend rate N/A 2034 2037 2037 A 1% change in the assumed health care cost trend rate would have the following effects for the year ended and as at December 31, 2019 : Canada United States 1% Increase 1% Decrease 1% Increase 1% Decrease (millions of Canadian dollars) Total service and interest costs 1 (1 ) 1 (1 ) Accumulated postretirement benefit obligation 21 (17 ) 19 (17 ) PLAN ASSETS We manage the investment risk of our pension funds by setting a long-term asset mix policy for each plan after consideration of: (i) the nature of pension plan liabilities; (ii) the investment horizon of the plan; (iii) the going concern and solvency funded status and cash flow requirements of the plan; (iv) our operating environment and financial situation and our ability to withstand fluctuations in pension contributions; and (v) the future economic and capital markets outlook with respect to investment returns, volatility of returns and correlation between assets. The overall expected rate of return on plan assets is based on the asset allocation targets with estimates for returns based on long-term expectations. The asset allocation targets and major categories of plan assets are as follows: Canada United States Target December 31, Target December 31, Asset Category Allocation 2019 2018 Allocation 2019 2018 Equity securities 43.4 % 46.4 % 45.8 % 45.0 % 55.2 % 52.7 % Fixed income securities 30.3 % 31.0 % 38.8 % 20.0 % 19.8 % 34.9 % Alternatives 1 26.3 % 22.6 % 15.4 % 35.0 % 25.0 % 12.4 % 1 Alternatives include investments in private debt, private equity, infrastructure and real estate funds. Pension Plans The following table summarizes the fair value of plan assets for our pension plans recorded at each fair value hierarchy level: Canada United States Level 1 1 Level 2 2 Level 3 3 Total Level 1 1 Level 2 2 Level 3 3 Total (millions of Canadian dollars) December 31, 2019 Cash and cash equivalents 184 — — 184 14 — — 14 Equity securities Canada 165 183 — 348 — — — — United States — — — — — 93 — 93 Global — 1,429 — 1,429 — 516 — 516 Fixed income securities Government 196 418 — 614 — 164 — 164 Corporate — 388 — 388 — 41 — 41 Alternatives 4 — — 852 852 — — 276 276 Forward currency contracts — 12 — 12 — — — — Total pension plan assets at fair value 545 2,430 852 3,827 14 814 276 1,104 December 31, 2018 Cash and cash equivalents 240 — — 240 56 — — 56 Equity securities Canada 138 481 — 619 — — — — United States — — — — — 110 — 110 Global — 992 — 992 — 440 — 440 Fixed income securities Government 218 453 — 671 — 265 — 265 Corporate — 457 — 457 — 44 — 44 Alternatives 4 — — 562 562 — — 130 130 Forward currency contracts — (18 ) — (18 ) — — — — Total pension plan assets at fair value 596 2,365 562 3,523 56 859 130 1,045 1 Level 1 assets include assets with quoted prices in active markets for identical assets. 2 Level 2 assets include assets with significant observable inputs. 3 Level 3 assets include assets with significant unobservable inputs. 4 Alternatives include investments in private debt, private equity, infrastructure and real estate funds. Changes in the net fair value of pension plan assets classified as Level 3 in the fair value hierarchy were as follows: Canada United States December 31, 2019 2018 2019 2018 (millions of Canadian dollars) Balance at beginning of year 562 340 130 56 Unrealized and realized gains 10 77 13 9 Purchases and settlements, net 280 145 133 65 Balance at end of year 852 562 276 130 OPEB Plans The following table summarizes the fair value of plan assets for our OPEB plans recorded at each fair value hierarchy level: Canada United States Level 1 1 Level 2 2 Level 3 3 Total Level 1 1 Level 2 2 Level 3 3 Total (millions of Canadian dollars) December 31, 2019 Cash and cash equivalents — — — — 2 — — 2 Equity securities United States — — — — — 75 — 75 Global — — — — — 38 — 38 Fixed income securities Government — — — — 40 15 — 55 Alternatives 4 — — — — — — 18 18 Total OPEB plan assets at fair value — — — — 42 128 18 188 December 31, 2018 Cash and cash equivalents — — — — 7 — — 7 Equity securities United States — — — — — 68 — 68 Global — — — — — 30 — 30 Fixed income securities Government — — — — 43 28 — 71 Corporate — — — — — — — — Alternatives 4 — — — — — — 5 5 Total OPEB plan assets at fair value — — — — 50 126 5 181 1 Level 1 assets include assets with quoted prices in active markets for identical assets. 2 Level 2 assets include assets with significant observable inputs. 3 Level 3 assets include assets with significant unobservable inputs. 4 Alternatives includes investments in private debt, private equity, infrastructure and real estate. Changes in the net fair value of OPEB plan assets classified as Level 3 in the fair value hierarchy were as follows: Canada United States December 31, 2019 2018 2019 2018 (millions of Canadian dollars) Balance at beginning of year — — 5 — Unrealized and realized gains — — 1 — Purchases and settlements, net — — 12 5 Balance at end of year — — 18 5 EXPECTED BENEFIT PAYMENTS Year ending December 31, 2020 2021 2022 2023 2024 2025-2029 (millions of Canadian dollars) Pension Canada 180 186 192 198 204 1,105 United States 87 90 91 89 91 402 OPEB Canada 12 12 12 13 13 69 United States 23 22 21 20 19 82 EXPECTED EMPLOYER CONTRIBUTIONS In 2020 , we expect to contribute approximately $104 million and $31 million to the Canadian and United States pension plans, respectively, and $12 million and $8 million to the Canadian and United States OPEB plans, respectively. RETIREMENT SAVINGS PLANS In addition to the pension and OPEB plans discussed above, we also have defined contribution employee savings plans available to both Canadian and United States employees. Employees may participate in a matching contribution where we match a certain percentage of before-tax employee contributions of up to 2.5% and 6.0% of eligible pay per pay period for Canadian and United States employees, respectively. For the years ended December 31, 2019 , 2018 and 2017 , pre-tax employer matching contribution costs were $4 million , $ 13 million and $14 million for Canadian employees and $ 27 million , $ 27 million and $ 31 million for United States employees, respectively.

LEASES

LEASES	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
LEASES	LEASES LESSEE We incur operating lease expenses related primarily to real estate, pipelines, storage and equipment. Our operating leases have remaining lease terms of 3 months to 28 years . For the year ended December 31, 2019 , we incurred operating lease expenses of $113 million . Operating lease expenses are reported under Operating and administrative expenses on the Consolidated Statements of Earnings. For the year ended December 31, 2019 , operating lease payments to settle lease liabilities were $123 million . Operating lease payments are reported under operating activities in the Consolidated Statements of Cash Flows. Supplemental Statements of Financial Position Information December 31, 2019 January 1, 2019 (millions of Canadian dollars, except lease term and discount rate) Operating leases Operating lease right-of-use assets, net 1 713 771 Operating lease liabilities - current 2 94 86 Operating lease liabilities - long-term 3 689 770 Total operating lease liabilities 783 856 Weighted average remaining lease term Operating leases 13 years 14 years Weighted average discount rate Operating leases 4.3 % 4.3 % 1 Right-of-use assets are reported under Deferred amounts and other assets in the Consolidated Statements of Financial Position. 2 Current lease liabilities are reported under Accounts payable and other in the Consolidated Statements of Financial Position. 3 Long-term lease liabilities are reported under Other long-term liabilities in the Consolidated Statements of Financial Position. As at December 31, 2019 , our operating lease liabilities are expected to mature as follows: Operating leases (millions of Canadian dollars) 2020 128 2021 99 2022 94 2023 84 2024 79 Thereafter 588 Total undiscounted lease payments 1,072 Less imputed interest (289 ) Total operating lease liabilities 783 LESSOR We receive revenues from operating leases primarily related to natural gas and crude oil storage and processing facilities, rail cars, and wind power generation assets. Our operating leases have remaining lease terms of 2 months to 24 years . Year ended December 31, 2019 (millions of Canadian dollars) Operating lease income 265 Variable lease income 360 Total lease income 1 625 1 Lease income is recorded under Transportation and other services in the Consolidated Statements of Earnings. As at December 31, 2019 , the following table sets out future lease payments to be received under operating lease contracts where we are the lessor: Operating leases (millions of Canadian dollars) 2020 236 2021 199 2022 188 2023 180 2024 178 Thereafter 2,276 Future lease payments 3,257
LEASES	LEASES LESSEE We incur operating lease expenses related primarily to real estate, pipelines, storage and equipment. Our operating leases have remaining lease terms of 3 months to 28 years . For the year ended December 31, 2019 , we incurred operating lease expenses of $113 million . Operating lease expenses are reported under Operating and administrative expenses on the Consolidated Statements of Earnings. For the year ended December 31, 2019 , operating lease payments to settle lease liabilities were $123 million . Operating lease payments are reported under operating activities in the Consolidated Statements of Cash Flows. Supplemental Statements of Financial Position Information December 31, 2019 January 1, 2019 (millions of Canadian dollars, except lease term and discount rate) Operating leases Operating lease right-of-use assets, net 1 713 771 Operating lease liabilities - current 2 94 86 Operating lease liabilities - long-term 3 689 770 Total operating lease liabilities 783 856 Weighted average remaining lease term Operating leases 13 years 14 years Weighted average discount rate Operating leases 4.3 % 4.3 % 1 Right-of-use assets are reported under Deferred amounts and other assets in the Consolidated Statements of Financial Position. 2 Current lease liabilities are reported under Accounts payable and other in the Consolidated Statements of Financial Position. 3 Long-term lease liabilities are reported under Other long-term liabilities in the Consolidated Statements of Financial Position. As at December 31, 2019 , our operating lease liabilities are expected to mature as follows: Operating leases (millions of Canadian dollars) 2020 128 2021 99 2022 94 2023 84 2024 79 Thereafter 588 Total undiscounted lease payments 1,072 Less imputed interest (289 ) Total operating lease liabilities 783 LESSOR We receive revenues from operating leases primarily related to natural gas and crude oil storage and processing facilities, rail cars, and wind power generation assets. Our operating leases have remaining lease terms of 2 months to 24 years . Year ended December 31, 2019 (millions of Canadian dollars) Operating lease income 265 Variable lease income 360 Total lease income 1 625 1 Lease income is recorded under Transportation and other services in the Consolidated Statements of Earnings. As at December 31, 2019 , the following table sets out future lease payments to be received under operating lease contracts where we are the lessor: Operating leases (millions of Canadian dollars) 2020 236 2021 199 2022 188 2023 180 2024 178 Thereafter 2,276 Future lease payments 3,257

CHANGES IN OPERATING ASSETS AND

CHANGES IN OPERATING ASSETS AND LIABILITIES	12 Months Ended
	Dec. 31, 2019
CHANGES IN OPERATING ASSETS AND LIABILITIES
CHANGES IN OPERATING ASSETS AND LIABILITIES	CHANGES IN OPERATING ASSETS AND LIABILITIES Year ended December 31, 2019 2018 2017 (millions of Canadian dollars) Accounts receivable and other (659 ) 857 (783 ) Accounts receivable from affiliates 6 54 24 Inventory (24 ) 164 (289 ) Deferred amounts and other assets 133 226 (138 ) Accounts payable and other 175 (151 ) 277 Accounts payable to affiliates (24 ) (122 ) (62 ) Interest payable (41 ) 25 124 Other long-term liabilities 175 (138 ) 509 (259 ) 915 (338 )

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS Related party transactions are conducted in the normal course of business and unless otherwise noted, are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. SERVICE AGREEMENTS Vector, a joint venture, contracts our services to operate the pipeline. Amounts for these services, which are charged at cost in accordance with service agreements, were $7 million , $7 million and $14 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. TRANSPORTATION AGREEMENTS Certain wholly-owned subsidiaries within the Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution and Storage and Energy Services segments have committed and uncommitted transportation arrangements with several joint venture affiliates that are accounted for using the equity method. Total amounts charged to us for transportation services for the years ended December 31, 2019 , 2018 and 2017 were $812 million , $572 million and $721 million , respectively. AFFILIATE REVENUES AND PURCHASES Certain wholly-owned subsidiaries within the Energy Services segments made natural gas and NGL purchases of $392 million , $322 million and $142 million from several joint venture affiliates during the years ended December 31, 2019 , 2018 and 2017 , respectively. In addition to this, Enbridge recorded transportation and natural gas sales of $145 million , $122 million and $60 million within the Energy Services and Gas Distribution and Storage segments to equity investment affiliates during the years ended December 31, 2019 , 2018 and 2017 , respectively. DCP Midstream processes certain of our pipeline customers' gas to meet gas quality specifications in order to be transported on our system. DCP Midstream processes the gas and sells the NGLs that are extracted from the gas. A portion of the proceeds from those sales are retained by DCP Midstream and the balance is remitted to us. We received proceeds of $ 34 million (US$ 26 million), $ 52 million (US$ 40 million ) and $47 million (US $36 million ) during the years ended December 31, 2019 , 2018 and 2017, respectively, from DCP Midstream related to those sales. In addition to the above, we recorded other revenues from several joint venture affiliates related to the transportation and storage of natural gas of $ 69 million (US$ 52 million ), $ 14 million (US$ 11 million ) and $4 million (US $3 million ) during the years ended December 31, 2019 , 2018 and 2017, respectively. In the ordinary course of business, we are reimbursed by joint venture partners for operating and maintenance expenses for certain projects. We received reimbursements from these joint ventures of $ 48 million (US$ 36 million ), $ 28 million (US$ 22 million ) and $10 million (US $8 million ) during the years ended December 31, 2019 , 2018 and 2017, respectively. LONG-TERM NOTES RECEIVABLE FROM AFFILIATES As at December 31, 2019 , amounts receivable from affiliates include a series of loans totaling $1,023 million ( $769 million as at December 31, 2018 ), which require quarterly interest payments at annual interest rates ranging from 3% to 8% . These amounts are included in deferred amounts and other assets in the Consolidated Statements of Financial position.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES COMMITMENTS At December 31, 2019 , we have commitments as detailed below: Total Less than 1 year 2 years 3 years 4 years 5 years Thereafter (millions of Canadian dollars) Annual debt maturities 1 63,585 4,394 6,856 4,054 2,585 7,712 37,984 Interest obligations 2 29,498 2,416 2,296 2,216 2,076 1,915 18,579 Purchase of services, pipe and other materials, including transportation 3,4 9,448 2,891 1,507 1,217 564 570 2,699 Maintenance agreements 435 56 55 53 25 20 226 Land lease commitments 1,190 30 35 35 35 36 1,019 Total 104,156 9,787 10,749 7,575 5,285 10,253 60,507 1 Includes debentures, term notes, commercial paper and credit facility draws based on the facility's maturity date and excludes short-term borrowings, debt discount, debt issue costs and finance lease obligations. We have the ability under certain debt facilities to call and repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments could be materially different than presented above. 2 Includes debentures and term notes bearing interest at fixed, floating and fixed-to-floating rates. 3 Includes capital and operating commitments. 4 Consists primarily of gas transportation and storage contracts, firm capacity payments and gas purchase commitments, transportation, service and product purchase obligations, and power commitments. ENVIRONMENTAL We are subject to various Canadian and US federal, state and local laws relating to the protection of the environment. These laws and regulations can change from time to time, imposing new obligations on us. Environmental risk is inherent to liquid hydrocarbon and natural gas pipeline operations, and Enbridge and our affiliates are, at times, subject to environmental remediation obligations at various sites where we operate. We manage this environmental risk through appropriate environmental policies, programs and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover payment for environmental liabilities from insurance or other potentially responsible parties, we will be responsible for payment of costs arising from environmental incidents associated with the operating activities of our liquids and natural gas businesses. AUX SABLE On October 14, 2016, an amended claim was filed against Aux Sable by a counterparty to an NGL supply agreement. On January 5, 2017, Aux Sable filed a Statement of Defence with respect to this claim. On November 27, 2019, the counterparty filed an amended amended claim providing further particulars of its claim against Aux Sable, increasing its damages claimed, and adding defendants Aux Sable Liquid Products Inc. and Aux Sable Extraction LLC (general partners of the previously existing defendants). Aux Sable filed an amended Statement of Defence responding to the amended amended claim on January 31, 2020. While the final outcome of this action cannot be predicted with certainty, at this time management believes that the ultimate resolution of this action will not have a material impact on our consolidated financial position or results of operations. TAX MATTERS We and our subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review. OTHER LITIGATION We and our subsidiaries are subject to various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our consolidated financial position or results of operations.

GUARANTEES

GUARANTEES	12 Months Ended
	Dec. 31, 2019
Guarantees [Abstract]
GUARANTEES	GUARANTEES In the normal course of conducting business, we enter into agreements which indemnify third parties and affiliates. We may also be a party to agreements with subsidiaries, jointly owned entities, unconsolidated entities such as equity method investees, or entities with other ownership arrangements that require us to provide financial and performance guarantees. Financial guarantees include stand-by letters of credit, debt guarantees, surety bonds and indemnifications. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on our Consolidated Statements of Financial Position. Performance guarantees require us to make payments to a third party if the guaranteed affiliate entity does not perform on its contractual obligations, such as debt agreements, purchase or sale agreements, and construction contracts and leases. We typically enter into these arrangements to facilitate commercial transactions with third parties. Examples include indemnifying counterparties pursuant to sale agreements for assets or businesses in matters such as breaches of representations, warranties or covenants, loss or damages to property, environmental liabilities, and litigation and contingent liabilities. We may indemnify third parties for certain liabilities relating to environmental matters arising from operations prior to the purchase or transfer of certain assets and interests. Similarly, we may indemnify the purchaser of assets for certain tax liabilities incurred while we owned the assets, a misrepresentation related to taxes that result in a loss to the purchaser or other certain tax liabilities related to those assets. The likelihood of having to perform under these guarantees and indemnifications is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. We cannot reasonably estimate the total maximum potential amounts that could become payable to third parties and affiliates under such agreements described above; however, historically, we have not made any significant payments under guarantee or indemnification provisions. While these agreements may specify a maximum potential exposure, or a specified duration to the guarantee or indemnification obligation, there are circumstances where the amount and duration are unlimited. As at December 31, 2019 guarantees and indemnifications have not had, and are not reasonably likely to have, a material effect on our financial condition, changes in financial condition, earnings, liquidity, capital expenditures or capital resources. Please refer to Note 12 - Variable Interest Entities for further discussion regarding specific guarantees related to unconsolidated VIEs.

CONDENSED CONSOLIDATING FINANCI

CONDENSED CONSOLIDATING FINANCIAL INFORMATION	12 Months Ended
	Dec. 31, 2019
Condensed Financial Information Disclosure [Abstract]
CONDENSED CONSOLIDATED FINANCIAL INFORMATION	CONDENSED CONSOLIDATING FINANCIAL INFORMATION On January 22, 2019, Enbridge entered into supplemental indentures with its wholly-owned subsidiaries, the Partnerships, pursuant to which Enbridge fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations of the Partnerships with respect to the outstanding series of notes issued under the respective indentures of the Partnerships. Concurrently, the Partnerships entered into a subsidiary guarantee agreement pursuant to which they fully and unconditionally guaranteed, on a senior unsecured basis, the outstanding series of senior notes of Enbridge. As a result of the guarantees, holders of any of the outstanding guaranteed notes of the Partnerships are in the same position with respect to the net assets, income and cash flows of Enbridge as holders of Enbridge's outstanding guaranteed notes, and vice versa. Other than the Partnerships, Enbridge subsidiaries (including the subsidiaries of the Partnerships, collectively, the Subsidiary Non-Guarantors), are not parties to the subsidiary guarantee agreement and have not otherwise guaranteed any of Enbridge's outstanding series of senior notes. Consenting SEP notes and EEP notes under Guarantee SEP Notes 1 EEP Notes 2 Floating Rate Senior Notes due 2020 4.200% Notes due 2021 4.600% Senior Notes due 2021 5.875% Notes due 2025 4.750% Senior Notes due 2024 5.950% Notes due 2033 3.500% Senior Notes due 2025 6.300% Notes due 2034 3.375% Senior Notes due 2026 7.500% Notes due 2038 5.950% Senior Notes due 2043 5.500% Notes due 2040 4.500% Senior Notes due 2045 7.375% Notes due 2045 1 As at December 31, 2019 , the aggregate outstanding principal amount of SEP notes was approximately US $3.9 billion . 2 As at December 31, 2019 , the aggregate outstanding principal amount of EEP notes was approximately US $3.0 billion . Enbridge Notes under Guarantees USD Denominated 1 CAD Denominated 2 Senior Floating Rate Notes due 2020 4.530% Senior Notes due 2020 Senior Floating Rate Notes due 2020 4.850% Senior Notes due 2020 2.900% Senior Notes due 2022 4.260% Senior Notes due 2021 4.000% Senior Notes due 2023 3.160% Senior Notes due 2021 3.500% Senior Notes due 2024 4.850% Senior Notes due 2022 2.500% Senior Notes due 2025 3.190% Senior Notes due 2022 4.250% Senior Notes due 2026 3.940% Senior Notes due 2023 3.700% Senior Notes due 2027 3.940% Senior Notes due 2023 3.125% Senior Notes due 2029 3.950% Senior Notes due 2024 4.500% Senior Notes due 2044 3.200% Senior Notes due 2027 5.500% Senior Notes due 2046 6.100% Senior Notes due 2028 4.000% Senior Notes due 2049 2.990% Senior Notes due 2029 7.220% Senior Notes due 2030 7.200% Senior Notes due 2032 5.570% Senior Notes due 2035 5.750% Senior Notes due 2039 5.120% Senior Notes due 2040 4.240% Senior Notes due 2042 4.570% Senior Notes due 2044 4.870% Senior Notes due 2044 4.560% Senior Notes due 2064 1 As at December 31, 2019 , the aggregate outstanding principal amount of the Enbridge United States dollar denominated notes was approximately US $7.9 billion . 2 As at December 31, 2019 , the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was approximately $7.6 billion . In accordance with Rule 3-10 of the United States Securities and Exchange Commission's Regulation S-X, which provides an exemption from the reporting requirements of the Securities Exchange Act of 1934 for subsidiary issuers of guaranteed securities and subsidiary guarantors, in lieu of filing separate financial statements for each of the Partnerships, we have included the accompanying condensed consolidating financial information with separate columns representing the following: 1. Enbridge Inc., the Parent Issuer and Guarantor; 2. SEP, a Subsidiary Issuer and Guarantor; 3. EEP, a Subsidiary Issuer and Guarantor; 4. Subsidiary Non-Guarantors, as defined herein; 5. Consolidating and elimination entries required to consolidate the Parent Issuer and Guarantor and its subsidiaries, including the Subsidiary Issuers and Guarantors, and 6. Enbridge Inc. and subsidiaries on a consolidated basis. For the purposes of the condensed consolidating financial information only, investments in subsidiaries are accounted for under the equity method. In addition, the Condensed Consolidating Statements of Cash Flows present the intercompany loan and distribution activity, as well as cash collection and payments made on behalf of our subsidiaries, as cash activities. These intercompany investments and related activities eliminate on consolidation and are presented separately only for the purpose of the accompanying Condensed Consolidating Statements. Condensed Consolidating Statements of Earnings and Comprehensive Income for the year ended December 31, 2019 Parent Issuer and Guarantor Subsidiary Issuer and Guarantor - SEP Subsidiary Issuer and Guarantor - EEP Subsidiary Non-Guarantors Consolidating and elimination adjustments Consolidated - Enbridge (millions of Canadian dollars) Operating revenues Commodity sales — — — 29,309 — 29,309 Gas distribution sales — — — 4,205 — 4,205 Transportation and other services — — — 16,555 — 16,555 Total operating revenues — — — 50,069 — 50,069 Operating Expenses Commodity costs — — — 28,802 — 28,802 Gas distribution costs — — — 2,202 — 2,202 Operating and administrative 128 5 (16 ) 6,874 — 6,991 Depreciation and amortization 67 — — 3,324 — 3,391 Impairment of long-lived assets — — — 423 — 423 Impairment of goodwill — — — — — — Total operating expenses 195 5 (16 ) 41,625 — 41,809 Operating income/(loss) (195 ) (5 ) 16 8,444 — 8,260 Income from equity investments 70 133 — 1,366 (66 ) 1,503 Equity earnings from consolidated subsidiaries 3,881 1,189 1,043 1,696 (7,809 ) — Other — — — — — — Net foreign currency gain/(loss) 1,671 — — (106 ) (1,088 ) 477 Gain/(loss) on dispositions (7 ) — — (293 ) — (300 ) Other, including other income from affiliates 1,944 2 189 573 (2,450 ) 258 Interest expense (1,268 ) (330 ) (591 ) (2,966 ) 2,492 (2,663 ) Earnings before income taxes 6,096 989 657 8,714 (8,921 ) 7,535 Income tax (expense)/recovery (391 ) 44 6 (1,985 ) 618 (1,708 ) Earnings 5,705 1,033 663 6,729 (8,303 ) 5,827 Earnings attributable to noncontrolling interests and redeemable noncontrolling interests — — — — (122 ) (122 ) Earnings attributable to controlling interests 5,705 1,033 663 6,729 (8,425 ) 5,705 Preference share dividends (383 ) — — — — (383 ) Earnings attributable to common shareholders 5,322 1,033 663 6,729 (8,425 ) 5,322 Earnings 5,705 1,033 663 6,729 (8,303 ) 5,827 Total other comprehensive income/(loss) (2,992 ) (67 ) 51 (929 ) 830 (3,107 ) Comprehensive income 2,713 966 714 5,800 (7,473 ) 2,720 Comprehensive income attributable to noncontrolling interests — — — — (7 ) (7 ) Comprehensive income attributable to controlling interests 2,713 966 714 5,800 (7,480 ) 2,713 Condensed Consolidating Statements of Earnings and Comprehensive Income for the year ended December 31, 2018 Parent Issuer and Guarantor Subsidiary Issuer and Guarantor - SEP Subsidiary Issuer and Guarantor - EEP Subsidiary Non-Guarantors Consolidating and elimination adjustments Consolidated - Enbridge (millions of Canadian dollars) Operating revenues Commodity sales — — — 27,660 — 27,660 Gas distribution sales — — — 4,360 — 4,360 Transportation and other services — — — 14,358 — 14,358 Total operating revenues — — — 46,378 — 46,378 Operating Expenses Commodity costs — — — 26,818 — 26,818 Gas distribution costs — — — 2,583 — 2,583 Operating and administrative 180 14 54 6,622 (78 ) 6,792 Depreciation and amortization 59 — — 3,187 — 3,246 Impairment of long-lived assets — — — 1,104 — 1,104 Impairment of goodwill — — — 1,019 — 1,019 Total operating expenses 239 14 54 41,333 (78 ) 41,562 Operating income/(loss) (239 ) (14 ) (54 ) 5,045 78 4,816 Income from equity investments 302 142 — 1,360 (295 ) 1,509 Equity earnings/(loss) from consolidated subsidiaries 3,119 (1,634 ) 921 (1,581 ) (825 ) — Other Net foreign currency gain/(loss) (829 ) 8 — 80 219 (522 ) Gain/(loss) on dispositions 360 — — (406 ) — (46 ) Other, including other income/(expense) from affiliates 945 72 153 254 (908 ) 516 Interest expense (1,080 ) (302 ) (557 ) (1,689 ) 925 (2,703 ) Earnings/(loss) before income taxes 2,578 (1,728 ) 463 3,063 (806 ) 3,570 Income tax recovery/(expense) 304 (319 ) 3 (4,373 ) 4,148 (237 ) Earnings/(loss) 2,882 (2,047 ) 466 (1,310 ) 3,342 3,333 Earnings attributable to noncontrolling interests and redeemable noncontrolling interests — — — — (451 ) (451 ) Earnings/(loss) attributable to controlling interests 2,882 (2,047 ) 466 (1,310 ) 2,891 2,882 Preference share dividends (367 ) — — — — (367 ) Earnings/(loss) attributable to common shareholders 2,515 (2,047 ) 466 (1,310 ) 2,891 2,515 Earnings/(loss) 2,882 (2,047 ) 466 (1,310 ) 3,342 3,333 Total other comprehensive income/(loss) 3,788 (9 ) 28 556 (225 ) 4,138 Comprehensive income/(loss) 6,670 (2,056 ) 494 (754 ) 3,117 7,471 Comprehensive income attributable to noncontrolling interests — — — — (801 ) (801 ) Comprehensive income/(loss) attributable to controlling interests 6,670 (2,056 ) 494 (754 ) 2,316 6,670 Condensed Consolidating Statements of Earnings and Comprehensive Income for the year ended December 31, 2017 Parent Issuer and Guarantor Subsidiary Issuer and Guarantor - SEP Subsidiary Issuer and Guarantor - EEP Subsidiary Non-Guarantors Consolidating and elimination adjustments Consolidated - Enbridge (millions of Canadian dollars) Operating revenues Commodity sales — — — 26,286 — 26,286 Gas distribution sales — — — 4,215 — 4,215 Transportation and other services — — — 13,877 — 13,877 Total operating revenues — — — 44,378 — 44,378 Operating expenses Commodity costs — — — 26,065 — 26,065 Gas distribution costs — — — 2,572 — 2,572 Operating and administrative 169 146 16 6,111 — 6,442 Depreciation and amortization 56 — — 3,107 — 3,163 Impairment of long lived assets — — — 4,463 — 4,463 Impairment of goodwill — — — 102 — 102 Total operating expenses 225 146 16 42,420 — 42,807 Operating income/(loss) (225 ) (146 ) (16 ) 1,958 — 1,571 Income from equity investments 471 118 — 981 (468 ) 1,102 Equity earnings from consolidated subsidiaries 2,130 752 926 881 (4,689 ) — Other Net foreign currency gain/(loss) 500 — — (22 ) (241 ) 237 Gain/(loss) on dispositions (11 ) — — 27 — 16 Other, including other income/(expense) from affiliates 871 11 139 74 (896 ) 199 Interest expense (816 ) (221 ) (691 ) (1,753 ) 925 (2,556 ) Earnings before income taxes 2,920 514 358 2,146 (5,369 ) 569 Income tax (expense)/recovery (61 ) — 9 2,706 43 2,697 Earnings 2,859 514 367 4,852 (5,326 ) 3,266 Earnings attributable to noncontrolling interests and redeemable noncontrolling interests — — — — (407 ) (407 ) Earnings attributable to controlling interests 2,859 514 367 4,852 (5,733 ) 2,859 Preference share dividends (330 ) — — — — (330 ) Earnings attributable to common shareholders 2,529 514 367 4,852 (5,733 ) 2,529 Earnings 2,859 514 367 4,852 (5,326 ) 3,266 Total other comprehensive income/(loss) (2,031 ) 12 204 (412 ) (51 ) (2,278 ) Comprehensive income 828 526 571 4,440 (5,377 ) 988 Comprehensive income attributable to noncontrolling interests — — — — (160 ) (160 ) Comprehensive income attributable to controlling interests 828 526 571 4,440 (5,537 ) 828 Condensed Consolidating Statements of Financial Position as at December 31, 2019 Parent Issuer and Guarantor Subsidiary Issuer and Guarantor - SEP Subsidiary Issuer and Guarantor - EEP Subsidiary Non-Guarantors Consolidating and elimination adjustments Consolidated - Enbridge (millions of Canadian dollars) Assets Current assets Cash and cash equivalents — 33 4 611 — 648 Restricted cash 9 — — 19 — 28 Accounts receivable and other 429 8 4 6,340 — 6,781 Accounts receivable from affiliates 746 — 12 (164 ) (525 ) 69 Short-term loans receivable from affiliates 1,691 — 3,961 4,417 (10,069 ) — Inventory — — — 1,299 — 1,299 2,875 41 3,981 12,522 (10,594 ) 8,825 Property, plant and equipment, net 248 — — 93,475 — 93,723 Long-term loans receivable from affiliates 47,285 73 2,387 35,672 (85,417 ) — Investments in subsidiaries 80,456 18,956 5,180 14,782 (119,374 ) — Long-term investments 1,701 932 — 14,467 (572 ) 16,528 Restricted long-term investments — — — 434 — 434 Deferred amounts and other assets 998 1 1 7,282 (849 ) 7,433 Intangible assets, net 247 — — 1,926 — 2,173 Goodwill — — — 33,153 — 33,153 Deferred income taxes 486 — — 514 — 1,000 Total assets 134,296 20,003 11,549 214,227 (216,806 ) 163,269 Liabilities and equity Current liabilities Short-term borrowings — — — 898 — 898 Accounts payable and other 2,765 28 1 7,745 (476 ) 10,063 Accounts payable to affiliates 736 367 83 (640 ) (525 ) 21 Interest payable 279 52 51 242 — 624 Short-term loans payable to affiliates 367 2,058 1,991 5,653 (10,069 ) — Current portion of long-term debt 2,160 518 — 1,726 — 4,404 6,307 3,023 2,126 15,624 (11,070 ) 16,010 Long-term debt 27,290 4,435 3,789 24,147 — 59,661 Other long-term liabilities 1,295 2 12 7,864 (849 ) 8,324 Long-term loans payable to affiliates 33,686 — 3,112 48,619 (85,417 ) — Deferred income taxes — 271 — 13,887 (4,291 ) 9,867 68,578 7,731 9,039 110,141 (101,627 ) 93,862 Equity Controlling interests 1 65,718 12,272 2,510 104,086 (118,543 ) 66,043 Noncontrolling interests — — — — 3,364 3,364 65,718 12,272 2,510 104,086 (115,179 ) 69,407 Total liabilities and equity 134,296 20,003 11,549 214,227 (216,806 ) 163,269 1 Equity attributable to controlling interests for parent issuer and guarantor excludes reciprocal shareholding balance included within consolidating and elimination adjustments. Condensed Consolidating Statements of Financial Position as at December 31, 2018 Parent Issuer and Guarantor Subsidiary Issuer and Guarantor - SEP Subsidiary Issuer and Guarantor - EEP Subsidiary Non-Guarantors Consolidating and elimination adjustments Consolidated - Enbridge (millions of Canadian dollars) Assets Current assets Cash and cash equivalents — 16 — 502 — 518 Restricted cash 9 — — 110 — 119 Accounts receivable and other 283 15 8 6,211 — 6,517 Accounts receivable from affiliates 726 — 13 (142 ) (518 ) 79 Short-term loans receivable from affiliates 3,943 — 3,689 653 (8,285 ) — Inventory — — — 1,339 — 1,339 4,961 31 3,710 8,673 (8,803 ) 8,572 Property, plant and equipment, net 140 — — 94,400 — 94,540 Long-term loans receivable from affiliates 10,318 73 2,539 1,344 (14,274 ) — Investments in subsidiaries 78,474 19,777 6,363 15,567 (120,181 ) — Long-term investments 4,561 987 — 14,841 (3,682 ) 16,707 Restricted long-term investments — — — 323 — 323 Deferred amounts and other assets 1,700 9 17 8,558 (1,726 ) 8,558 Intangible assets, net 234 — — 2,138 — 2,372 Goodwill — — — 34,459 — 34,459 Deferred income taxes 817 — — 229 328 1,374 Total assets 101,205 20,877 12,629 180,532 (148,338 ) 166,905 Liabilities and equity Current liabilities Short-term borrowings — — — 1,024 — 1,024 Accounts payable and other 2,742 7 34 7,059 (6 ) 9,836 Accounts payable to affiliates 946 233 56 (677 ) (518 ) 40 Interest payable 283 56 105 225 — 669 Short-term loans payable to affiliates 426 682 — 7,177 (8,285 ) — Environmental liabilities, current — — — 27 — 27 Current portion of long-term debt 1,853 — 683 723 — 3,259 6,250 978 878 15,558 (8,809 ) 14,855 Long-term debt 22,893 7,276 6,943 23,215 — 60,327 Other long-term liabilities 2,428 2 30 8,100 (1,726 ) 8,834 Long-term loans payable to affiliates 76 — 1,502 12,696 (14,274 ) — Deferred income taxes — 331 — 13,523 (4,400 ) 9,454 31,647 8,587 9,353 73,092 (29,209 ) 93,470 Equity Controlling interests 1 69,558 12,290 3,276 107,440 (123,094 ) 69,470 Noncontrolling interests — — — — 3,965 3,965 69,558 12,290 3,276 107,440 (119,129 ) 73,435 Total liabilities and equity 101,205 20,877 12,629 180,532 (148,338 ) 166,905 1 Equity attributable to controlling interests for parent issuer and guarantor excludes reciprocal shareholding balance included within consolidating and elimination adjustments. Condensed Consolidating Statements of Cash Flows for the year ended December 31, 2019 Parent Issuer and Guarantor Subsidiary Issuer and Guarantor - SEP Subsidiary Issuer and Guarantor - EEP Subsidiary Non-Guarantors Consolidating and elimination adjustments Consolidated - Enbridge (millions of Canadian dollars) Net cash provided by operating activities 2,246 1,676 (365 ) 9,675 (3,834 ) 9,398 Investing activities Capital expenditures (75 ) — — (5,417 ) — (5,492 ) Long-term investments and restricted long-term investments (26 ) (11 ) — (1,122 ) — (1,159 ) Distributions from equity investments in excess of cumulative earnings — 24 1,196 393 (1,196 ) 417 Additions to intangible assets (68 ) — — (132 ) — (200 ) Affiliate loans, net — — — (314 ) — (314 ) Proceeds from disposition — — — 2,110 — 2,110 Contributions to subsidiaries (4,759 ) — (12 ) — 4,771 — Return of share capital from subsidiary companies 5,281 — — — (5,281 ) — Advances to affiliates (50,897 ) — (2,778 ) (60,787 ) 114,462 — Repayment of advances to affiliates 15,808 — 2,357 22,136 (40,301 ) — Other — — — (20 ) — (20 ) Net cash (used in)/provided by investing activities (34,736 ) 13 763 (43,153 ) 72,455 (4,658 ) Financing activities Net change in short-term borrowings — — — (127 ) — (127 ) Net change in commercial paper and credit facility draws 3,158 (2,011 ) (1,017 ) 695 — 825 Debenture and term note issues, net of issue costs 3,621 — — 2,555 — 6,176 Debenture and term note repayments (1,450 ) — (2,514 ) (704 ) — (4,668 ) Contributions from noncontrolling interests — — — — 12 12 Distributions to noncontrolling interests — — — — (254 ) (254 ) Contributions from redeemable noncontrolling interests — — — — — — Distributions to redeemable noncontrolling interests — — — — — — Contributions from parents — — — 4,771 (4,771 ) — Distributions to parents — (1,014 ) (651 ) (8,888 ) 10,553 — Redemption of preferred shares — — — (300 ) — (300 ) Common shares issued 18 — — — — 18 Preference share dividends (383 ) — — — — (383 ) Common share dividends (5,973 ) — — — — (5,973 ) Advances from affiliates 46,860 5,678 8,249 53,675 (114,462 ) — Repayment of advances from affiliates (13,361 ) (4,321 ) (4,454 ) (18,165 ) 40,301 — Other — (4 ) (7 ) (60 ) — (71 ) Net cash provided by/(used in) financing activities 32,490 (1,672 ) (394 ) 33,452 (68,621 ) (4,745 ) Effect of translation of foreign denominated cash and cash equivalents and restricted cash — — — 44 — 44 Net increase/(decrease) in cash and cash equivalents and restricted cash — 17 4 18 — 39 Cash and cash equivalents and restricted cash at beginning of year 9 16 — 612 — 637 Cash and cash equivalents and restricted cash at end of year 9 33 4 630 — 676 Condensed Consolidating Statements of Cash Flows for the year ended December 31, 2018 Parent Issuer and Guarantor Subsidiary Issuer and Guarantor - SEP Subsidiary Issuer and Guarantor - EEP Subsidiary Non-Guarantors Consolidating and elimination adjustments Consolidated - Enbridge (millions of Canadian dollars) Net cash provided by/(used in) operating activities 1,696 1,751 (239 ) 11,683 (4,389 ) 10,502 Investing activities Capital expenditures (28 ) — — (6,778 ) — (6,806 ) Long-term investments and restricted long-term investments (81 ) (12 ) — (1,297 ) 78 (1,312 ) Distributions from equity investments in excess of cumulative earnings 287 45 982 1,232 (1,269 ) 1,277 Additions to intangible assets (43 ) — — (497 ) — (540 ) Proceeds from dispositions 1,790 — — 2,662 — 4,452 Contributions to subsidiaries (8,131 ) (79 ) (13 ) (1,655 ) 9,878 — Return of share capital from subsidiaries 3,753 — — — (3,753 ) — Advances to affiliates (6,863 ) — (1,703 ) (5,685 ) 14,251 — Repayment of advances to affiliates 9,427 518 1,504 4,124 (15,573 ) — Affiliate loans, net (76 ) (76 ) Other — — — (12 ) — (12 ) Net cash provided by/(used in) investing activities 111 472 770 (7,982 ) 3,612 (3,017 ) Financing activities Net change in short-term borrowings — — — (420 ) — (420 ) Net change in commercial paper and credit facility draws (734 ) (962 ) (1,009 ) 449 — (2,256 ) Debenture and term note issues, net of issue costs 2,554 — — 983 — 3,537 Debenture and term note repayments — (648 ) (509 ) (3,288 ) — (4,445 ) Sale of noncontrolling interests in subsidiaries — — — — 1,289 1,289 Contributions from noncontrolling interests — — — — 24 24 Distributions to noncontrolling interests — — — — (857 ) (857 ) Contributions from redeemable noncontrolling interests — — — — 70 70 Distributions to redeemable noncontrolling interests — — — — (325 ) (325 ) Contributions from parents — — 1,007 8,223 (9,230 ) — Distributions to parents — (1,902 ) (666 ) (6,564 ) 9,132 — Sponsored Vehicle buy-in cash payment (64 ) — — — — (64 ) Redemption of preferred shares — — — (210 ) — (210 ) Common shares issued 21 648 — — (648 ) 21 Preference share dividends (364 ) — — — — (364 ) Common share dividends (3,480 ) — — — — (3,480 ) Advances from affiliates 710 1,474 3,501 8,566 (14,251 ) — Repayment of advances from affiliates (443 ) (826 ) (2,855 ) (11,449 ) 15,573 — Other — (5 ) — (18 ) — (23 ) Net cash (used in)/provided by financing activities (1,800 ) (2,221 ) (531 ) (3,728 ) 777 (7,503 ) Effect of translation of foreign denominated cash and cash equivalents and restricted cash — — — 68 — 68 Net increase in cash and cash equivalents and restricted cash 7 2 — 41 — 50 Cash and cash equivalents and restricted cash at beginning of year 2 14 — 571 — 587 Cash and cash equivalents and restricted cash at end of year 9 16 — 612 — 637 Condensed Consolidating Statements of Cash Flows for the year ended December 31, 2017 Parent Issuer and Guarantor Subsidiary Issuer and Guarantor - SEP Subsidiary Issuer and Guarantor - EEP Subsidiary Non-Guarantors Consolidating and elimination adjustments Consolidated - Enbridge (millions of Canadian dollars) Net cash (used in)/provided by operating activities 620 355 (695 ) 9,654 (3,276 ) 6,658 Investing activities Capital expenditures (21 ) — — (8,266 ) — (8,287 ) Long-term investments and restricted long-term investments (202 ) (51 ) — (3,535 ) 202 (3,586 ) Distributions from equity investments in excess of cumulative earnings 36 22 921 103 (957 ) 125 Additions to intangible assets (47 ) — — (742 ) — (789 ) Cash acquired in Merger Transaction — — — 682 — 682 Proceeds from dispositions — — 1,742 1,103 (2,217 ) 628 Contributions to subsidiaries (4,866 ) — (2,056 ) — 6,922 — Return of share capital from subsidiaries 2,192 — 1,532 — (3,724 ) — Advances to affiliates (7,145 ) (519 ) (1,410 ) (3,020 ) 12,094 — Repayment of advances to affiliates 4,506 — 2,129 2,887 (9,522 ) — Affiliate loans, net — — — (22 ) — (22 ) Other — — — 212 — 212 Net cash (used in)/provided by investing activities (5,547 ) (548 ) 2,858 (10,598 ) 2,798 (11,037 ) Financing activities Net change in short-term borrowings — — — 721 — 721 Net change in commercial paper and credit facility draws (1,845 ) 1,965 (316 ) (1,053 ) — (1,249 ) Debenture and term note issues, net of issue costs 8,177 519 — 787 — 9,483 Debenture and term note repayments (1,711 ) (533 ) — (2,810 ) — (5,054 ) Purchase of interest in consolidated subsidiary — — (475 ) (1,969 ) 2,217 (227 ) Contributions from noncontrolling interests — — — — 832 832 Distributions to noncontrolling interests — — — — (919 ) (919 ) Contributions from redeemable noncontrolling interests 563 — — — 615 1,178 Distributions to redeemable noncontrolling interests — — — — (247 ) (247 ) Contributions from parents — — — 6,922 (6,922 ) — Distributions to parents — (1,987 ) (789 ) (6,093 ) 8,869 — Preference shares issued 489 — — — — 489 Redemption of preferred shares — — (1,613 ) 1,613 — — Common shares issued 1,549 227 1,646 — (1,873 ) 1,549 Preference share dividends (330 ) — (478 ) — 478 (330 ) Common share dividends 1 (2,336 ) — — (414 ) — (2,750 ) Advances from affiliates 407 — 2,613 9,074 (12,094 ) — Repayment of advances from affiliates (40 ) — (2,847 ) (6,635 ) 9,522 — Net cash provided by/(used in) financing activities 4,923 191 (2,259 ) 143 478 3,476 Effect of translation of foreign denominated cash and cash equivalents and restricted cash — — (2 ) (70 ) — (72 ) Net decrease in cash and cash equivalents and restricted cash (4 ) (2 ) (98 ) (871 ) — (975 ) Cash and cash equivalents and restricted cash at beginning of year 6 16 98 1,442 — 1,562 Cash and cash equivalents and restricted cash at end of year 2 14 — 571 — 587 1 Common share dividends for the year ended December 31, 2017 includes amounts distributed by Spectra Energy Corp. related to dividends accrued prior to the Merger Transaction.

QUARTERLY FINANCIAL DATA (UNAUD

QUARTERLY FINANCIAL DATA (UNAUDITED)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
QUARTERLY FINANCIAL DATA (UNAUDITED)	QUARTERLY FINANCIAL DATA (UNAUDITED) Q1 Q2 Q3 Q4 Total (unaudited; millions of Canadian dollars, except per share amounts) 2019 Operating revenues 12,856 13,263 11,598 12,352 50,069 Operating income 2,619 2,285 1,588 1,768 8,260 Earnings 2,023 1,830 1,060 914 5,827 Earnings attributable to controlling interests 1,986 1,832 1,045 842 5,705 Earnings attributable to common shareholders 1,891 1,736 949 746 5,322 Earnings per common share Basic 0.94 0.86 0.47 0.37 2.64 Diluted 0.94 0.86 0.47 0.36 2.63 2018 Operating revenues 12,726 10,745 11,345 11,562 46,378 Operating income 878 1,571 854 1,513 4,816 Earnings 510 1,327 213 1,283 3,333 Earnings attributable to controlling interests 534 1,160 4 1,184 2,882 Earnings/(loss) attributable to common shareholders 445 1,071 (90 ) 1,089 2,515 Earnings/(loss) per common share Basic 0.26 0.63 (0.05 ) 0.60 1.46 Diluted 0.26 0.63 (0.05 ) 0.60 1.46

SIGNIFICANT ACCOUNTING POLICI_2

SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
BASIS OF PRESENTATION AND USE OF ESTIMATES	BASIS OF PRESENTATION AND USE OF ESTIMATES The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities in the consolidated financial statements. Significant estimates and assumptions used in the preparation of the consolidated financial statements include, but are not limited to: carrying values of regulatory assets and liabilities (Note 7) ; purchase price allocations (Note 8) ; unbilled revenues; depreciation rates and carrying value of property, plant and equipment (Note 11) ; amortization rates of intangible assets (Note 15) ; measurement of goodwill (Note 16) ; fair value of ARO (Note 19) ; valuation of stock-based compensation (Note 22) ; fair value of financial instruments (Note 24) ; provisions for income taxes (Note 25) ; assumptions used to measure retirement and other postretirement benefit obligations (OPEB) (Note 26) ; commitments and contingencies (Note 30) ; and estimates of losses related to environmental remediation obligations (Note 30)
PRINCIPLES OF CONSOLIDATION	PRINCIPLES OF CONSOLIDATION The consolidated financial statements include our accounts and accounts of our subsidiaries and VIEs for which we are the primary beneficiary. A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains and losses of the entity. Upon inception of a contractual agreement, we perform an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a VIE. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE entity that could potentially be significant to the VIE. Where we conclude that we are the primary beneficiary of a VIE, we consolidate the accounts of that VIE. We assess all variable interests in the entity and use our judgment when determining if we are the primary beneficiary. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. We assess the primary beneficiary determination for a VIE on an ongoing basis, if there are changes in the facts and circumstances related to a VIE. The consolidated financial statements also include the accounts of any limited partnerships where we represent the general partner and, based on all facts and circumstances, control such limited partnerships, unless the limited partner has substantive participating rights or substantive kick-out rights. For certain investments where we retain an undivided interest in assets and liabilities, we record our proportionate share of assets, liabilities, revenues and expenses. If an entity is determined to not be a VIE, the voting interest entity model is applied, where an investor holding the majority voting rights consolidates the entity. All significant intercompany accounts and transactions are eliminated upon consolidation. Ownership interests in subsidiaries represented by other parties that do not control the entity are presented in the consolidated financial statements as activities and balances attributable to noncontrolling interests and redeemable noncontrolling interests. Investments and entities over which we exercise significant influence are accounted for using the equity method.
REGULATION	REGULATION Certain parts of our businesses are subject to regulation by various authorities including, but not limited to, the CER, the FERC, the Alberta Energy Regulator, the OEB and La Régie de l’Energie du Québec. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under U.S. GAAP for non rate-regulated entities. Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates or expected to be paid to cover future abandonment costs in relation to the CER’s LMCI. Long-term regulatory assets are recorded in Deferred amounts and other assets and current regulatory assets are recorded in Accounts receivable and other. Long-term regulatory liabilities are included in Other long-term liabilities and current regulatory liabilities are recorded in Accounts payable and other. Regulatory assets are assessed for impairment if we identify an event indicative of possible impairment. The recognition of regulatory assets and liabilities is based on the actions, or expected future actions, of the regulator. To the extent that the regulator’s actions differ from our expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, we would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. A regulatory asset or liability is recognized in respect of deferred income taxes when it is expected the amounts will be recovered or settled through future regulator-approved rates. Allowance for funds used during construction (AFUDC) is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component, which are both capitalized based on rates set out in a regulatory agreement. The corresponding impact on earnings is included in Interest expense for the interest component and Other income for the equity component. In the absence of rate regulation, we would capitalize interest using a capitalization rate based on our cost of borrowing, whereas the capitalized equity component, the corresponding earnings during the construction phase and the subsequent depreciation relating to the equity component would not be recognized. For certain regulated operations to which U.S. GAAP guidance for phase-in plans applies, negotiated depreciation rates recovered in transportation tolls may be less than the depreciation expense calculated in accordance with U.S. GAAP in early years of long-term contracts but recovered in future periods when tolls exceed depreciation. Depreciation expense on such assets is recorded in accordance with U.S. GAAP and no deferred regulatory asset is recorded (Note 7) .
REVENUE RECOGNITION/NATIONAL GAS IMBALANCES	NATURAL GAS IMBALANCES The Consolidated Statements of Financial Position include in-kind balances as a result of differences in gas volumes received and delivered for customers. Since settlement of certain imbalances is in-kind, changes in the balances do not have an effect on our Consolidated Statements of Earnings or Consolidated Statements of Cash Flows. Most natural gas volumes owed to or by us are valued at natural gas market index prices as at the balance sheet dates. REVENUE RECOGNITION For businesses that are not rate-regulated, revenues are recorded when products have been delivered or services have been performed, the amount of revenue can be reliably measured and collectability is reasonably assured. Customer credit worthiness is assessed prior to agreement signing, as well as throughout the contract duration. Certain revenues from liquids and gas pipeline businesses are recognized under the terms of committed delivery contracts rather than the cash tolls received. Long-term take-or-pay contracts, under which shippers are obligated to pay fixed amounts rateably over the contract period regardless of volumes shipped, may contain make-up rights. Make-up rights are earned by shippers when minimum volume commitments are not utilized during the period but under certain circumstances can be used to offset overages in future periods, subject to expiry periods. We recognize revenues associated with make-up rights at the earlier of when the make-up volume is shipped, the make-up right expires or when it is determined that the likelihood that the shipper will utilize the make-up right is remote. Certain offshore pipeline transportation contracts require Enbridge to provide transportation services for the life of the underlying producing fields. Under these arrangements, shippers pay Enbridge a fixed monthly toll for a defined period of time which may be shorter than the estimated reserve life of the underlying producing fields, resulting in a contract period which extends past the period of cash collection. Fixed monthly toll revenues are recognized ratably over the committed volume made available to shippers throughout the contract period, regardless of when cash is received. For the years ended December 31, 2019 , 2018 and 2017 , cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements was $169 million , $208 million , and $196 million , respectively. For rate-regulated businesses, revenues are recognized in a manner that is consistent with the underlying agreements as approved by the regulators. Natural gas utilities revenues are recorded on the basis of regular meter readings and estimates of customer usage from the last meter reading to the end of the reporting period. Estimates are based on historical consumption patterns and heating degree days experienced. Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in our distribution franchise area. Since July 1, 2011, Canadian Mainline (excluding Lines 8 and 9) earnings are governed by the CTS, under which revenues are recorded when services are performed. Effective on that date, we prospectively discontinued the application of rate-regulated accounting for those assets with the exception of flow-through income taxes covered by specific rate orders. Our Energy Services segment enters into commodity purchase and sale arrangements that are recorded gross because the related contracts are not held for trading purposes and we are acting as the principal in the transactions. For our energy marketing contracts, an estimate of revenues and commodity costs for the month of December is included in the Consolidated Statements of Earnings for each year based on the best available volume and price data for the commodity delivered and received.
DERIVATIVE INSTRUMENTS AND HEDGING	DERIVATIVE INSTRUMENTS AND HEDGING Non-qualifying Derivatives Non-qualifying derivative instruments are used primarily to economically hedge foreign exchange, interest rate and commodity price earnings exposure. Non-qualifying derivatives are measured at fair value with changes in fair value recognized in earnings in Transportation and other services revenues, Commodity costs, Operating and administrative expense, Other income/(expense) and Interest expense. Derivatives in Qualifying Hedging Relationships We use derivative financial instruments to manage our exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to our share price. Hedge accounting is optional and requires Enbridge to document the hedging relationship and test the hedging item’s effectiveness in offsetting changes in fair values or cash flows of the underlying hedged item on an ongoing basis. We present the earnings effects of hedging items with the hedged transaction. Derivatives in qualifying hedging relationships are categorized as cash flow hedges, fair value hedges or net investment hedges. Cash Flow Hedges We use cash flow hedges to manage our exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to our share price. The change in the fair value of a cash flow hedging instrument is recorded in OCI and is reclassified to earnings when the hedged item impacts earnings. If a derivative instrument designated as a cash flow hedge ceases to be effective or is terminated, hedge accounting is discontinued and the gain or loss at that date is deferred in OCI and recognized in earnings concurrently with the related transaction. If an anticipated hedged transaction is no longer probable, the gain or loss is recognized immediately in earnings. Subsequent gains and losses from derivative instruments for which hedge accounting has been discontinued are recognized in earnings in the period in which they occur. Fair Value Hedges We may use fair value hedges to hedge the fair value of debt instruments. The change in the fair value of the hedging instrument is recorded in earnings with changes in the fair value of the hedged risk of the asset or liability that is designated as part of the hedging relationship. If a fair value hedge is discontinued or ceases to be effective, the hedged risk of the asset or liability ceases to be remeasured at fair value and the cumulative fair value adjustment to the carrying value of the hedged item is recognized in earnings over the remaining life of the hedged item. Net Investment Hedges Gains and losses arising from translation of net investment in foreign operations from their functional currencies to Enbridge’s Canadian dollar presentation currency are included in cumulative translation adjustments (CTA), a component of OCI. We designate foreign currency derivatives and United States dollar denominated debt as hedges of net investments in United States dollar denominated foreign operations. As a result, the change in the fair value of the foreign currency derivatives as well as the translation of United States dollar denominated debt are reflected in OCI. Amounts recognized previously in Accumulated other comprehensive income/(loss) (AOCI) are reclassified to earnings when there is a reduction of the hedged net investment resulting from disposal of a foreign operation. Classification of Derivatives We recognize the fair market value of derivative instruments on the Consolidated Statements of Financial Position as current and non-current assets or liabilities depending on the timing of the settlements and the resulting cash flows associated with the instruments. Fair value amounts related to cash flows occurring beyond one year are classified as non-current. Cash inflows and outflows related to derivative instruments are classified as Operating activities on the Consolidated Statements of Cash Flows. Balance Sheet Offset Assets and liabilities arising from derivative instruments may be offset in the Consolidated Statements of Financial Position when we have the legal right and intention to settle them on a net basis. Transaction Costs Transaction costs are incremental costs directly related to the acquisition of a financial asset or the issuance of a financial liability. We incur transaction costs primarily from the issuance of debt and account for these costs as a deduction from Long-term debt on the Statements of Financial Position. These costs are amortized using the effective interest rate method over the term of the related debt instrument and are recorded in Interest expense.
EQUITY INVESTMENTS	EQUITY INVESTMENTS Equity investments over which we exercise significant influence, but do not have controlling financial interests, are accounted for using the equity method. Equity investments are initially measured at cost and are adjusted for our proportionate share of undistributed equity earnings or loss. Equity investments are increased for contributions made to and decreased for distributions received from the investees. To the extent an equity investee undertakes activities necessary to commence its planned principal operations, we capitalize interest costs associated with the investment during such period.
RESTRICTED LONG-TERM INVESTMENTS	RESTRICTED LONG-TERM INVESTMENTS Long-term investments that are restricted as to withdrawal or usage, for the purposes of the CER’s LMCI, are presented as Restricted long-term investments on the Consolidated Statements of Financial Position.
OTHER INVESTMENTS	OTHER INVESTMENTS Generally, we classify equity investments in entities over which we do not exercise significant influence and that do not have readily determinable fair values as other investments measured at fair value measurement alternative and recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for an identical or similar investment of the same issuer. Investments in equity securities measured using the fair value measurement alternative are reviewed for impairment each reporting period. Equity investments with readily determinable fair values are measured at fair value through net income. Dividends received from investments in equity securities are recognized in earnings when the right to receive payment is established. Investments in debt securities are classified either as available for sale securities measured at fair value through OCI or as held to maturity securities measured at amortized cost.
NONCONTROLLING INTERESTS	NONCONTROLLING INTERESTS Noncontrolling interests represent ownership interests attributable to third parties in certain consolidated subsidiaries. The portion of equity not owned by us in such entities is reflected as Noncontrolling interests within the equity section of the Consolidated Statements of Financial Position.
INCOME TAXES	INCOME TAXES Income taxes are accounted for using the liability method. Deferred income tax assets and liabilities are recorded based on temporary differences between the tax bases of assets and liabilities and their carrying values for accounting purposes. Deferred income tax assets and liabilities are measured using the tax rate that is expected to apply when the temporary differences reverse. For our regulated operations, a deferred income tax liability or asset is recognized with a corresponding regulatory asset or liability, respectively, to the extent taxes can be recovered through rates. Any interest and/or penalty incurred related to tax is reflected in income taxes.
FOREIGN CURRENCY TRANSACTIONS AND TRANSLATION	FOREIGN CURRENCY TRANSACTIONS AND TRANSLATION Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which Enbridge or a reporting subsidiary operates, referred to as the functional currency. Transactions denominated in foreign currencies are translated into the functional currency using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the rate of exchange in effect at the balance sheet date. Exchange gains and losses resulting from translation of monetary assets and liabilities are included in the Consolidated Statements of Earnings in the period in which they arise. Gains and losses arising from translation of foreign operations’ functional currencies to our Canadian dollar presentation currency are included in the CTA component of AOCI and are recognized in earnings upon sale of the foreign operation. Asset and liability accounts are translated at the exchange rates in effect on the balance sheet date, while revenues and expenses are translated using monthly average exchange rates.
CASH AND CASH EQUIVALENTS	CASH AND CASH EQUIVALENTS Cash and cash equivalents include short-term investments with a term to maturity of three months or less when purchased.
RESTRICTED CASH	RESTRICTED CASH Cash and cash equivalents that are restricted as to withdrawal or usage, in accordance with specific commercial arrangements, are presented as Restricted cash on the Consolidated Statements of Financial Position.
LOANS AND RECEIVABLES	LOANS AND RECEIVABLES Affiliate long-term notes receivable are measured at amortized cost using the effective interest rate method, net of any impairment losses recognized. Accounts receivable and other are measured at cost.
ALLOWANCE FOR DOUBTFUL ACCOUNTS	ALLOWANCE FOR DOUBTFUL ACCOUNTS Allowance for doubtful accounts is determined based on collection history. When we have determined that further collection efforts are unlikely to be successful, amounts charged to the allowance for doubtful accounts are applied against the impaired accounts receivable.
INVENTORY	INVENTORY Inventory is comprised of natural gas in storage held in Enbridge Gas, and crude oil and natural gas held primarily by energy services businesses in the Energy Services segment. Natural gas in storage in Enbridge Gas is recorded at the quarterly prices approved by the OEB in the determination of distribution rates. The actual price of gas purchased may differ from the OEB approved price. The difference between the approved price and the actual cost of the gas purchased is deferred as a liability for future refund or as an asset for collection as approved by the OEB. Other commodities inventory is recorded at the lower of cost, as determined on a weighted average basis, or market value. Upon disposition, other commodities inventory is recorded to Commodity costs on the Consolidated Statements of Earnings at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value.
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is recorded at historical cost. Expenditures for construction, expansion, major renewals and betterments are capitalized. Maintenance and repair costs are expensed as incurred. Expenditures for project development are capitalized if they are expected to have future benefit. We capitalize interest incurred during construction for non-rate-regulated assets. For rate-regulated assets, AFUDC is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component. Two primary methods of depreciation are utilized. For distinct assets, depreciation is generally provided on a straight-line basis over the estimated useful lives of the assets commencing when the asset is placed in service. For largely homogeneous groups of assets with comparable useful lives, the pool method of accounting for property, plant and equipment is followed whereby similar assets are grouped and depreciated as a pool. When group assets are retired or otherwise disposed of, gains and losses are generally not reflected in earnings but are booked as an adjustment to accumulated depreciation.
DEFERRED AMOUNTS AND OTHER ASSETS	DEFERRED AMOUNTS AND OTHER ASSETS Deferred amounts and other assets primarily include costs which regulatory authorities have permitted, or are expected to permit, to be recovered through future rates including: deferred income taxes; contractual receivables under the terms of long-term delivery contracts; derivative financial instruments; and actuarial gains and losses arising from defined benefit pension plans.
INTANGIBLE ASSETS	INTANGIBLE ASSETS Intangible assets consist primarily of certain software costs, customer relationships and emission allowances. We capitalize costs incurred during the application development stage of internal use software projects . Customer relationships represent the underlying relationship from long-term agreements with customers that are capitalized upon acquisition. From January 1, 2017 through July 3, 2018, emission allowances, which are recorded at their original cost, were purchased in order to meet GHG compliance obligations. Intangible assets are generally amortized on a straight-line basis over their expected lives, commencing when the asset is available for use, with the exception of emission allowances, which are not amortized as they will be used to satisfy compliance obligations as they come due.
GOODWILL	GOODWILL Goodwill represents the excess of the purchase price over the fair value of net identifiable assets on acquisition of a business. The carrying value of goodwill, which is not amortized, is assessed for impairment annually, or more frequently if events or changes in circumstances arise that suggest the carrying value of goodwill may be impaired. We perform our annual review of the goodwill balance on April 1. We perform our annual review for impairment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. We have the option to first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment test. When performing a qualitative assessment, we determine the drivers of fair value for each reporting unit and evaluate whether those drivers have been positively or negatively affected by relevant events and circumstances since the last fair value assessment. Our evaluation includes, but is not limited to, assessment of macroeconomic trends, regulatory environments, capital accessibility, operating income trends, and industry conditions. Based on our assessment of the qualitative factors, if we determine it is more likely than not that the fair value of the reporting unit is less than it's carrying amount, a quantitative goodwill impairment test is performed. The quantitative goodwill impairment test involves determining the fair value of our reporting units and comparing those values to the carrying value of each reporting unit. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value. This amount should not exceed the carrying amount of goodwill. Fair value of our reporting units is estimated using a combination of discounted cash flow model and earnings multiples techniques. The determination of fair value using the discounted cash flow model technique requires the use of estimates and assumptions related to discount rates, projected operating income, terminal value growth rates, capital expenditures and working capital levels. The cash flow projections included significant judgments and assumptions relating to revenue growth rates and expected future capital expenditure. The determination of fair value using the earnings multiples technique requires assumptions to be made in relation to maintainable earnings and earnings multipliers for reporting units. The allocation of goodwill to held for sale and disposed businesses is based on the relative fair value of businesses included in the particular reporting unit.
IMPAIRMENT	IMPAIRMENT We review the carrying values of our long-lived assets as events or changes in circumstances warrant. If it is determined that the carrying value of an asset exceeds the undiscounted cash flows expected from the asset, we calculate fair value based on the discounted cash flows and write the assets down to the extent that the carrying value exceeds the fair value. With respect to investments in debt securities and equity investments, we assess at each balance sheet date whether there is objective evidence that a financial asset is impaired by completing a quantitative or qualitative analysis of factors impacting the investment. If there is objective evidence of impairment, we value the expected discounted cash flows using observable market inputs and determine whether the decline below carrying value is other than temporary. If the decline is determined to be other than temporary, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the asset. With respect to other financial assets, we assess the assets for impairment when there is no longer reasonable assurance of timely collection. If evidence of impairment is noted, we reduce the value of the financial asset to its estimated realizable amount, determined using discounted expected future cash flows.
ASSET RETIREMENT OBLIGATIONS	ASSET RETIREMENT OBLIGATIONS ARO associated with the retirement of long-lived assets are measured at fair value and recognized as Accounts payable and other or Other long-term liabilities in the period in which they can be reasonably determined. The fair value approximates the cost a third party would charge to perform the tasks necessary to retire such assets and is recognized at the present value of expected future cash flows. ARO are added to the carrying value of the associated asset and depreciated over the asset’s useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. Our estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements.
PENSION AND OTHER POSTRETIREMENT BENEFITS	PENSION AND OTHER POSTRETIREMENT BENEFITS We sponsor defined benefit and defined contribution pension plans, and defined benefit OPEB plans, which provide group health care, life insurance benefits and other postretirement benefits. Defined benefit pension obligation and net periodic benefit cost are estimated using the projected unit credit method, which incorporates management’s best estimates of future salary levels, other cost escalations, retirement ages of employees and other actuarial factors including discount rates and mortality. The OPEB benefit obligation and net periodic benefit cost are estimated using the projected unit credit method, where benefits are attributed to years of service, taking into consideration projection of benefit costs. We use mortality tables issued by the Society of Actuaries in the United States (revised in 2019) and the Canadian Institute of Actuaries (revised in 2014 ) to measure the benefit obligations of our United States pension plan (the United States Plan) and our Canadian pension plans (the Canadian Plans), respectively. We determine discount rates by reference to rates of high-quality long-term corporate bonds with maturities that approximate the timing of future payments we anticipate making under each of the respective plans. Funded pension and OPEB plan assets are measured at fair value. The expected return on funded pension and OPEB plan assets is determined using market related values and assumptions on the invested asset mix consistent with the investment policies relating to the plan assets. The market related values reflect estimated return on investments consistent with long-term historical averages for similar assets. Actuarial gains and losses arise from the difference between the actual and expected rate of return on plan assets for that period (funded pension and OPEB plans) or from changes in actuarial assumptions used to determine the accrued benefit obligation, including discount rate, changes in headcount and salary inflation experience. The excess of the fair value of a plan’s assets over the fair value of a plan’s benefit obligation is recognized as Deferred amounts and other assets in our Consolidated Statements of Financial Position. The excess of the fair value of a plan’s benefit obligation over the fair value of a plan’s assets is recognized as Accounts payable and other and Other long-term liabilities in our Consolidated Statements of Financial Position. Net periodic benefit cost is charged to Earnings and includes: • Cost of benefits provided in exchange for employee services rendered during the year (current service cost); • Interest cost of plan obligations; • Expected return on plan assets (funded pension and OPEB plans); • Amortization of prior service costs on a straight-line basis over the expected average remaining service period of the active employee group covered by the plans; and • Amortization of cumulative unrecognized net actuarial gains and losses in excess of 10% of the greater of the accrued benefit obligation or the fair value of plan assets, over the expected average remaining service life of the active employee group covered by the plans. Cumulative unrecognized net actuarial gains and losses and prior service costs arising from defined benefit pension plans for our non-utility operations and from defined benefit OPEB plans are presented as a component of AOCI in our Consolidated Statements of Changes in Equity. Any unrecognized actuarial gains and losses and prior service costs and credits related to those plans that arise during the period are recognized as a component of OCI, net of tax. Cumulative unrecognized net actuarial gains and losses and prior service costs arising from defined benefit pension plans for our utility operations, which have been permitted or are expected to be permitted by the Regulators, to be recovered through future rates, are presented as a component of Deferred amounts and other assets in our Consolidated Statements of Financial Position. Our utility operations also record regulatory adjustments to reflect the difference between certain net periodic benefit costs for accounting purposes and net periodic benefit costs for ratemaking purposes. Offsetting regulatory assets or liabilities are recorded to the extent net periodic benefit costs are expected to be collected from or refunded to customers, respectively, in future rates. In the absence of rate regulation, regulatory assets or liabilities would not be recorded and net periodic benefit costs would be charged to Earnings and OCI on an accrual basis. For defined contribution plans, contributions made by us are expensed in the period in which the contribution occurs.
STOCK-BASED COMPENSATION	STOCK-BASED COMPENSATION Incentive Stock Options (ISO) granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value of the ISO granted as calculated by the Black-Scholes-Merton model and is recognized on a straight-line basis over the shorter of the vesting period or the period to early retirement eligibility, with a corresponding credit to Additional paid-in capital. Balances in Additional paid-in capital are transferred to Share capital when the options are exercised. Performance Stock Units (PSU) and Restricted Stock Units (RSU) are cash settled awards for which the related liability is remeasured each reporting period. PSUs vest at the completion of a three-year term and RSUs vest at the completion of a 35 -month term. During the vesting term, compensation expense is recorded based on the number of units outstanding and the current market price of Enbridge’s shares with an offset to Accounts payable and other or to Other long-term liabilities. The value of the PSUs are also dependent on our performance relative to performance targets set out under the plan.
COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES	COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. We expense costs incurred for remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. We record liabilities for environmental matters when assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other factors. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual costs or new information and are included in Other long-term liabilities in the Consolidated Statements of Financial Position at their undiscounted amounts. There is always a potential of incurring additional costs in connection with environmental liabilities due to variations in any or all of the categories described above, including modified or revised requirements from regulatory agencies, in addition to fines and penalties, as well as expenditures associated with litigation and settlement of claims. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record and report an asset separately from the associated liability in the Consolidated Statements of Financial Position. Liabilities for other commitments and contingencies are recognized when, after fully analyzing available information, we determine it is either probable that an asset has been impaired, or that a liability has been incurred, and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we recognize the most likely amount, or if no amount is more likely than another, the minimum of the range of probable loss is accrued. We expense legal costs associated with loss contingencies as such costs are incurred.
CHANGES IN ACCOUNTING POLICIES	ADOPTION OF NEW ACCOUNTING STANDARDS Cloud Computing Arrangements Effective January 1, 2019, we adopted Accounting Standards Update (ASU) 2018-15 on a prospective basis. The new standard was issued to provide guidance on the accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. This ASU specifies that an entity would apply ASC 350-40, Internal-use software, to determine which implementation costs related to a hosting arrangement that is a service contract should be capitalized and which should be expensed. The amendments in the update also require that the capitalized costs be amortized on a straight-line basis generally over the term of the arrangement and presented in the same income statement line as fees paid for the hosting service, in addition to specifying that the capitalized costs must be presented on the same balance sheet line as the prepayment of fees related to the hosting arrangement. This ASU requires similar consistency in classifications from a cash flow statement perspective. The adoption of this ASU did not have a material impact on our consolidated financial statements. Improvements to Accounting for Hedging Activities Effective January 1, 2019, we adopted ASU 2017-12 on a modified retrospective basis. The new standard was issued with the objective of better aligning a company’s risk management activities and the resulting hedge accounting reflected in the financial statements. The amendments allow cash flow hedging of contractually specified components in financial and non-financial items. As a result of the new standard, hedge ineffectiveness will no longer be measured or recorded, and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The adoption of this accounting update did not have a material impact on our consolidated financial statements. Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium Effective January 1, 2019, we adopted ASU 2017-08 on a modified retrospective basis. The new standard was issued with the intent of shortening the amortization period to the earliest call date for certain callable debt securities held at a premium. The adoption of this accounting update did not have a material impact on our consolidated financial statements. Recognition of Leases Effective January 1, 2019 we adopted ASU 2016-02 Leases (Topic 842) using the modified retrospective approach. We recognize an arrangement as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We recognize right-of-use (ROU) assets and the related lease liabilities on the statement of financial position for operating lease arrangements with a term of 12 months or longer. We do not separate non-lease components from the associated lease components of our lessee contracts and account for both components as a single lease component. We combine lease and non-lease components within a contract for operating lessor leases when certain conditions are met. ROU assets are assessed for impairment using the same approach as is applied for other long-lived assets, as described under the Impairment section of the Significant Accounting Policies Note 2 in the annual consolidated financial statements. Lease liabilities and ROU assets require the use of judgment and estimates, which are applied in determining the term of a lease, appropriate discount rates, whether an arrangement contains a lease, whether there are any indicators of impairment for ROU assets and whether any ROU assets should be grouped with other long-lived assets for impairment testing. In adopting Topic 842, we elected the package of practical expedients permitted under the transition guidance. The election to apply the package of practical expedients allows an entity to not apply the new lease standard to the prior year comparative periods in the year of adoption. The application of the package of practical expedients also permits entities not to reassess whether any expired or existing contracts contain leases in accordance with the new guidance, lease classifications, and whether initial direct costs capitalized under current guidance continue to meet the definition of initial direct costs under the new guidance. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements that had commenced prior to January 1, 2019. On January 1, 2019, ROU assets and corresponding lease liabilities of $771 million were recorded in connection with the adoption of Topic 842. When added to the $85 million of pre-existing liabilities relating to operating leases for which we no longer utilize the leased assets, total lease liabilities at January 1, 2019 were $856 million . All lease liabilities were measured using a weighted average discount rate of 4.32% . The adoption of this standard had no impact to the Consolidated Statements of Earnings, Comprehensive Income, Changes in Equity or Cash Flows during the period. Improvements to Related Party Guidance for Variable Interest Entities Effective September 30, 2019, we adopted ASU 2018-17 on a retrospective basis. The new standard was issued with the objective to improve the related party guidance on determining whether fees paid to decision makers and service providers (decision maker fees) are variable interests. Under the new guidance, reporting entities must consider indirect interests held through related parties in common control arrangements on a proportionate basis, rather than as the equivalent of a direct interest in its entirety, when determining if decision maker fees constitute a variable interest. The adoption of this ASU did not have a material impact on our consolidated financial statements. FUTURE ACCOUNTING POLICY CHANGES Accounting for Income Taxes ASU 2019-12 was issued in December 2019 with the intent of simplifying the accounting for income taxes. The accounting update removes certain exceptions to the general principles in ASC 740 as well as provides simplification by clarifying and amending existing guidance. ASU 2019-12 is effective January 1, 2021 and entities are permitted to adopt the standard early. We are currently assessing the impact of the new standard on our consolidated financial statements. Clarifying Interaction between Collaborative Arrangements and Revenue from Contracts with Customers ASU 2018-18 was issued in November 2018 to provide clarity on when transactions between entities in a collaborative arrangement should be accounted for under the new revenue standard, ASC 606. In determining whether transactions in collaborative arrangements should be accounted under the revenue standard, the update specifies that entities shall apply unit of account guidance to identify distinct goods or services and whether such goods and services are separately identifiable from other promises in the contract. ASU 2018-18 also precludes entities from presenting transactions with a collaborative partner which are not in scope of the new revenue standard together with revenue from contracts with customers. The accounting update is effective January 1, 2020 and early adoption is permitted. The adoption of ASU 2018-18 is not expected to have a material impact on our consolidated financial statements. Disclosure Effectiveness In August 2018, the Financial Accounting Standards Board issued two amendments as a part of its disclosure framework project aimed to improve the effectiveness of disclosures in the notes to financial statements. ASU 2018-14 was issued in August 2018 to improve disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The amendment modifies the current guidance by adding and removing several disclosure requirements while also clarifying the guidance on current disclosure requirements. ASU 2018-14 is effective January 1, 2021 and entities are permitted to adopt the standard early. The adoption of ASU 2018-14 is not expected to have a material impact on our consolidated financial statements. ASU 2018-13 was issued to improve the disclosure requirements for fair value measurements by eliminating and modifying some disclosures, while also adding new disclosures. This update is effective January 1, 2020, however entities are permitted to early adopt the eliminated or modified disclosures. The adoption of ASU 2018-13 is not expected to have a material impact on our consolidated financial statements. Accounting for Credit Losses ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delay the recognition until it is probable a loss has been incurred. The accounting update adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity will recognize as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. Further, ASU 2018-19 was issued in November 2018 to clarify that operating lease receivables should be accounted for under the new leases standard, ASC 842, and are not within the scope of ASC 326, Financial Instruments - Credit Losses. Both accounting updates are effective January 1, 2020. We have performed a detailed evaluation as of December 31, 2019 and do not anticipate the adoption of ASU 2016-13 to have a material impact on our consolidated financial statements.

REVENUE (Tables)

REVENUE (Tables)	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	Major Products and Services Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated Year ended December 31, 2019 (millions of Canadian dollars) Transportation revenue 9,082 4,477 743 — — — 14,302 Storage and other revenue 109 268 201 — — — 578 Gas gathering and processing revenue — 423 — — — — 423 Gas distribution revenue — — 4,210 — — — 4,210 Electricity and transmission revenue — — — 180 — — 180 Commodity sales — 4 — — — — 4 Total revenue from contracts with customers 9,191 5,172 5,154 180 — — 19,697 Commodity sales — — — — 29,305 — 29,305 Other revenue 1,2 659 30 9 387 (2 ) (16 ) 1,067 Intersegment revenue 369 5 16 — 71 (461 ) — Total revenue 10,219 5,207 5,179 567 29,374 (477 ) 50,069 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated Year ended December 31, 2018 (millions of Canadian dollars) Transportation revenue 8,488 3,928 875 — — — 13,291 Storage and other revenue 101 222 196 — — — 519 Gas gathering and processing revenue — 815 — — — — 815 Gas distribution revenue — — 4,376 — — — 4,376 Electricity and transmission revenue — — — 206 — — 206 Commodity sales — 1,590 — — — — 1,590 Total revenue from contracts with customers 8,589 6,555 5,447 206 — — 20,797 Commodity sales — — — — 26,070 — 26,070 Other revenue 1,2 (894 ) 6 9 361 4 25 (489 ) Intersegment revenue 384 10 14 — 154 (562 ) — Total revenue 8,079 6,571 5,470 567 26,228 (537 ) 46,378 1 Includes mark-to-market gains/(losses) from our hedging program. 2 Includes revenues from lease contracts. Refer to Note 27 Leases.
Contract with Customer, Asset and Liability	Contract Receivables Contract Assets Contract Liabilities (millions of Canadian dollars) Balance as at December 31, 2018 1,929 191 1,297 Balance as at December 31, 2019 2,099 216 1,424
Performance Obligations	Performance Obligations Segment Nature of Performance Obligation Liquids Pipelines • Transportation and storage of crude oil and NGLs Gas Transmission and Midstream • Transportation, storage, gathering, compression and treating of natural gas • Transportation of NGLs • Sale of crude oil, natural gas and NGLs Gas Distribution and Storage • Supply and delivery of natural gas • Transportation of natural gas • Storage of natural gas Renewable Power Generation • Generation and transmission of electricity • Delivery of electricity from renewable energy generation facilities
Schedule of New Accounting Pronouncements and Changes in Accounting Principles	Recognition and Measurement of Revenue Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Consolidated Year ended December 31, 2019 (millions of Canadian dollars) Revenue from products transferred at a point in time — 4 65 — — 69 Revenue from products and services transferred over time 1 9,191 5,168 5,089 180 — 19,628 Total revenue from contracts with customers 9,191 5,172 5,154 180 — 19,697 1 Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural gas distribution, natural gas storage services and electricity sales. Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Consolidated Year ended December 31, 2018 (millions of Canadian dollars) Revenue from products transferred at a point in time 1 — 1,590 68 — — 1,658 Revenue from products and services transferred over time 2 8,589 4,965 5,379 206 — 19,139 Total revenue from contracts with customers 8,589 6,555 5,447 206 — 20,797 1 Revenue from sales of crude oil, natural gas and NGLs. Revenue from commodity sales where the commodity sold is not immediately consumed prior to use is recognized at the point in time when the contractually specified volume of the commodity has been delivered. 2 Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural gas distribution, natural gas storage services and electricity sales.

SEGMENTED INFORMATION (Tables)

SEGMENTED INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Schedule of reporting information by segment	Segmented information for the years ended December 31, 2019 , 2018 and 2017 is as follows: Year ended December 31, 2019 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues 10,219 5,207 5,179 567 29,374 (477 ) 50,069 Commodity and gas distribution costs (29 ) — (2,354 ) (2 ) (29,091 ) 472 (31,004 ) Operating and administrative (3,298 ) (2,232 ) (1,149 ) (189 ) (44 ) (79 ) (6,991 ) Impairment of long-lived assets (21 ) (105 ) — (297 ) — — (423 ) Income/(loss) from equity investments 780 682 4 31 8 (2 ) 1,503 Other income/(expense) 30 (181 ) 67 1 3 515 435 Earnings before interest, income tax expense, and depreciation and amortization 7,681 3,371 1,747 111 250 429 13,589 Depreciation and amortization (3,391 ) Interest expense (2,663 ) Income tax expense (1,708 ) Earnings 5,827 Capital expenditures 1 2,548 1,753 1,100 23 2 124 5,550 Total property, plant and equipment, net 48,783 25,268 15,622 3,658 24 368 93,723 Year ended December 31, 2018 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues 8,079 6,571 5,470 567 26,228 (537 ) 46,378 Commodity and gas distribution costs (16 ) (1,481 ) (2,748 ) (7 ) (25,689 ) 540 (29,401 ) Operating and administrative (3,124 ) (2,102 ) (1,111 ) (157 ) (73 ) (225 ) (6,792 ) Impairment of long-lived assets (180 ) (914 ) — (4 ) — (6 ) (1,104 ) Impairment of goodwill — (1,019 ) — — — — (1,019 ) Income/(loss) from equity investments 577 930 11 (28 ) 18 1 1,509 Other income/(expense) (5 ) 349 89 (2 ) (2 ) (481 ) (52 ) Earnings/(loss) before interest, income tax expense, and depreciation and amortization 5,331 2,334 1,711 369 482 (708 ) 9,519 Depreciation and amortization (3,246 ) Interest expense (2,703 ) Income tax expense (237 ) Earnings 3,333 Capital expenditures 1 3,102 2,644 1,066 33 — 27 6,872 Total property, plant and equipment, net 49,214 25,601 15,148 4,335 22 220 94,540 Year ended December 31, 2017 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues 8,913 7,067 4,992 534 23,282 (410 ) 44,378 Commodity and gas distribution costs (18 ) (2,834 ) (2,689 ) — (23,508 ) 412 (28,637 ) Operating and administrative (2,949 ) (1,756 ) (960 ) (163 ) (47 ) (567 ) (6,442 ) Impairment of long-lived assets — (4,463 ) — — — — (4,463 ) Impairment of goodwill — (102 ) — — — — (102 ) Income/(loss) from equity investments 416 653 23 6 8 (4 ) 1,102 Other income/(expense) 33 166 24 (5 ) 2 232 452 Earnings/(loss) before interest, income tax expense, and depreciation and amortization 6,395 (1,269 ) 1,390 372 (263 ) (337 ) 6,288 Depreciation and amortization (3,163 ) Interest expense (2,556 ) Income tax recovery 2,697 Earnings 3,266 Capital expenditures 1 2,799 4,016 1,177 321 1 108 8,422 1 Includes allowance for equity funds used during construction.
Schedule of revenues by geographical segments	Revenues 1 Year ended December 31, 2019 2018 2017 (millions of Canadian dollars) Canada 19,954 19,023 18,076 United States 30,115 27,355 26,302 50,069 46,378 44,378 1 Revenues are based on the country of origin of the product or service sold.
Schedule of property, plant and equipment by geographical segments	Property, Plant and Equipment 1 December 31, 2019 2018 (millions of Canadian dollars) Canada 45,993 44,716 United States 47,730 49,824 93,723 94,540 1 Amounts are based on the location where the assets are held.

EARNINGS PER COMMON SHARE (Tabl

EARNINGS PER COMMON SHARE (Tables)	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Schedule of Weighted Average Shares Outstanding Used to Calculate Basic and Diluted Earnings Per Share	Weighted average shares outstanding used to calculate basic and diluted earnings per share are as follows: December 31, 2019 2018 2017 (number of shares in millions) Weighted average shares outstanding 2,017 1,724 1,525 Effect of dilutive options 3 3 7 Diluted weighted average shares outstanding 2,020 1,727 1,532

REGULATORY MATTERS (Tables)

REGULATORY MATTERS (Tables)	12 Months Ended
	Dec. 31, 2019
Regulated Operations [Abstract]
Schedule of Regulatory Assets	Accounting for rate-regulated activities has resulted in the recognition of the following significant regulatory assets and liabilities on the Consolidated Statements of Financial Position: December 31, Recovery/Refund Period Ends 2019 2018 (millions of Canadian dollars) Regulatory assets/(liabilities), net Liquids Pipelines Deferred income taxes 1 Various 1,767 1,673 Tolling deferrals Various (25 ) (28 ) Recoverable income taxes Through 2040 24 27 Pipeline future abandonment costs 2 Various (293 ) (201 ) Other deferrals Various 32 — Gas Transmission and Midstream Deferred income taxes 1 Various 511 826 Regulatory liability related to income taxes 3 Various (866 ) (912 ) Long-term debt 4 Various 108 124 Pipeline future abandonment costs 2 Various (159 ) (111 ) Other Various 215 205 Gas Distribution and Storage Deferred income taxes 1 Various 1,273 1,132 Purchased gas variance 2020 (19 ) 197 Pension plans and OPEB Various 275 118 Future removal and site restoration reserves 5 Various (1,424 ) (1,107 ) Federal carbon program 2020 145 — Long-term debt 4 Various 362 387 Constant dollar net salvage adjustment 2018 — 6 Other Various 88 (4 ) 1 The deferred income taxes balance represents the regulatory offset to deferred income tax liabilities to the extent that it is expected to be included in regulator-approved future rates and recovered from future customers. The recovery period depends on the timing of the reversal of the temporary differences. In the absence of rate-regulated accounting, this regulatory balance and the related earnings impact would not be recorded. 2 The pipeline future abandonment costs liability results from amounts collected and set aside in accordance with the CER’s LMCI to cover future abandonment costs for CER regulated Canadian pipelines. Funds collected are included in Restricted long-term investments (Note 14) .Concurrently, we reflect the future abandonment cost as a regulatory liability. The settlement of this balance will occur as pipeline abandonment costs are incurred. 3 Relates to the establishment of a regulatory liability as a result of the United States tax reform legislation enacted December 22, 2017. 4 The debt balance represents our regulatory offset to the fair value adjustment to debt that resulted from the merger with Spectra Energy. The offset is viewed as a proxy for the regulatory asset that would be recorded in the event such debt was extinguished at an amount higher than the carrying value. 5 Future removal and site restoration reserves result from amounts collected from customers by us, with the approval of the OEB, to fund future costs for removal and site restoration relating to property, plant and equipment. These costs are collected as part of depreciation charged on property, plant and equipment that is recorded in rates. The balance represents the amount that we have collected from customers, net of actual costs expended on removal and site restoration. The settlement of this balance will occur over the long-term as future removal and site restoration costs are incurred. In the absence of rate-regulated accounting, costs incurred for removal and site restoration would be charged to earnings as incurred with recognition of revenue for amounts previously collected.
Schedule of Regulatory Liabilities	Accounting for rate-regulated activities has resulted in the recognition of the following significant regulatory assets and liabilities on the Consolidated Statements of Financial Position: December 31, Recovery/Refund Period Ends 2019 2018 (millions of Canadian dollars) Regulatory assets/(liabilities), net Liquids Pipelines Deferred income taxes 1 Various 1,767 1,673 Tolling deferrals Various (25 ) (28 ) Recoverable income taxes Through 2040 24 27 Pipeline future abandonment costs 2 Various (293 ) (201 ) Other deferrals Various 32 — Gas Transmission and Midstream Deferred income taxes 1 Various 511 826 Regulatory liability related to income taxes 3 Various (866 ) (912 ) Long-term debt 4 Various 108 124 Pipeline future abandonment costs 2 Various (159 ) (111 ) Other Various 215 205 Gas Distribution and Storage Deferred income taxes 1 Various 1,273 1,132 Purchased gas variance 2020 (19 ) 197 Pension plans and OPEB Various 275 118 Future removal and site restoration reserves 5 Various (1,424 ) (1,107 ) Federal carbon program 2020 145 — Long-term debt 4 Various 362 387 Constant dollar net salvage adjustment 2018 — 6 Other Various 88 (4 ) 1 The deferred income taxes balance represents the regulatory offset to deferred income tax liabilities to the extent that it is expected to be included in regulator-approved future rates and recovered from future customers. The recovery period depends on the timing of the reversal of the temporary differences. In the absence of rate-regulated accounting, this regulatory balance and the related earnings impact would not be recorded. 2 The pipeline future abandonment costs liability results from amounts collected and set aside in accordance with the CER’s LMCI to cover future abandonment costs for CER regulated Canadian pipelines. Funds collected are included in Restricted long-term investments (Note 14) .Concurrently, we reflect the future abandonment cost as a regulatory liability. The settlement of this balance will occur as pipeline abandonment costs are incurred. 3 Relates to the establishment of a regulatory liability as a result of the United States tax reform legislation enacted December 22, 2017. 4 The debt balance represents our regulatory offset to the fair value adjustment to debt that resulted from the merger with Spectra Energy. The offset is viewed as a proxy for the regulatory asset that would be recorded in the event such debt was extinguished at an amount higher than the carrying value. 5 Future removal and site restoration reserves result from amounts collected from customers by us, with the approval of the OEB, to fund future costs for removal and site restoration relating to property, plant and equipment. These costs are collected as part of depreciation charged on property, plant and equipment that is recorded in rates. The balance represents the amount that we have collected from customers, net of actual costs expended on removal and site restoration. The settlement of this balance will occur over the long-term as future removal and site restoration costs are incurred. In the absence of rate-regulated accounting, costs incurred for removal and site restoration would be charged to earnings as incurred with recognition of revenue for amounts previously collected.

ACQUISITIONS AND DISPOSITIONS (

ACQUISITIONS AND DISPOSITIONS (Tables)	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Summary of Estimated Fair Values Assigned to Net Assets and Final Purchase Price Allocation	The following table summarizes the estimated fair values that were assigned to the net assets of Spectra Energy: February 27, 2017 (millions of Canadian dollars) Fair value of net assets acquired: Current assets (a) 2,432 Property, plant and equipment, net (b) 33,555 Restricted long-term investments 144 Long-term investments (c) 5,000 Deferred amounts and other assets (d) 2,390 Intangible assets, net (e) 1,288 Current liabilities (a) (3,982 ) Long-term debt (d) (21,444 ) Other long-term liabilities (1,983 ) Deferred income taxes (b) (7,670 ) Noncontrolling interests (f) (8,877 ) 853 Goodwill (g) 36,656 37,509 Purchase price: Common shares 37,429 Cash 3 Fair value of outstanding earned stock compensation awards recorded in Additional paid-in capital 77 37,509 a) Accounts receivable is comprised primarily of customer trade receivables and natural gas imbalances. As such, the fair value of accounts receivable approximates the net carrying value of $1,174 million . The gross amount due of $1,190 million , of which $16 million is not expected to be collected, is included in current assets. During the fourth quarter of 2017, we identified certain transactions that were not reflected in the purchase price equation. This resulted in a $67 million and $548 million increase in current assets and current liabilities, respectively, and a $481 million decrease in long-term debt. b) We have applied the valuation methodologies described in ASC 820 Fair Value Measurements and Disclosures , to value the property, plant and equipment purchased. The fair value of Spectra Energy’s rate-regulated property, plant and equipment was determined using a market participant perspective, which is their carrying amount. The fair value of the remaining non-regulated property, plant and equipment was determined primarily using variations of the income approach, which is based on the present value of the future after-tax cash flows attributable to each non-regulated asset. Some of the more significant assumptions inherent in the development of the values, from the perspective of a market participant, include, but are not limited to, the amount and timing of projected future cash flows (including revenue and profitability); the discount rate selected to measure the risks inherent in the future cash flows; the assessment of the asset’s life cycle; the competitive trends impacting the asset; and customer turnover. During the third quarter of 2017, Spectra Energy's right-of-way agreements were reclassified from intangible assets to property, plant and equipment to conform the presentation of these agreements with our accounting policy pertaining to rights-of-way. The purchase price allocation above reflects this reclassification, which amounted to $830 million as at February 27, 2017. There is no change in the amortization period for the right-of-way agreements as a result of this reclassification. During the fourth quarter of 2017, we finalized our fair value measurement of the BC Pipeline & Field Services businesses, which resulted in decreases to property, plant and equipment of $1,955 million and deferred income tax liabilities of $661 million as at February 27, 2017. c) Long-term investments represent Spectra Energy’s 50% equity investment in DCP Midstream, Gulfstream Natural Gas System, L.L.C., NEXUS Gas Transmission, LLC (NEXUS), Steckman Ridge LP, Islander East Pipeline Company, L.L.C., Southeast Supply Header L.L.C., and 20% equity interest in PennEast Pipeline Company LLC (PennEast). The fair value of these investments was determined using an income approach. d) Fair value of long-term debt was determined based on the current underlying Government of Canada and United States Treasury interest rates on the corresponding bonds, as well as an implied credit spread based on current market conditions and resulted in an increase in the book value of debt of $1.5 billion . The fair value adjustment to long-term debt related to rate-regulated entities of $629 million also results in a regulatory offset in Deferred amounts and other assets in the Consolidated Statements of Financial Position. During the fourth quarter of 2017, deferred amounts and other assets decreased by $530 million as at February 27, 2017 due to the finalization of BC Pipelines & Field Services' fair value measurement, as discussed under (b) above. During the fourth quarter of 2017, we identified certain transactions that were not reflected in the purchase price equation. This resulted in a $481 million decrease in long-term debt, as discussed under (a) above. e) Intangible assets primarily consist of customer relationships in the non-regulated business, which represent the underlying relationship from long-term agreements with customers that are capitalized upon acquisition, determined using the income approach. Intangible assets are amortized on a straight-line basis over their expected lives. During the third quarter of 2017, intangible assets decreased by $830 million as at February 27, 2017 due to a reclassification to property, plant and equipment, as discussed under (b) above. The fair value of intangible assets acquired through the Merger Transaction, by major classes is as follows: Weighted Average Fair As at February 27, 2017 Amortization Rate Value (millions of Canadian dollars) Customer relationships 1 3.7 % 739 Project agreement 2 4.0 % 105 Software 11.1 % 329 Other 4.2 % 115 1,288 1 Represents customer relationships in the non-regulated business, which were capitalized upon acquisition. 2 Represents a project agreement between SEP, NextEra Energy, Inc., Duke Energy Corporation (Duke Energy) and Williams Partners L.P. In accordance with the agreement, payments will be made, based on our proportional ownership interest in Sabal Trail, as certain milestones of the project are met. Amortization of the intangible asset began on July 3, 2017 , when Sabal Trail was placed into service (Note 13) . f) The fair value of Spectra Energy’s noncontrolling interests includes approximately 78.4 million SEP common units outstanding to the public, valued at the February 24, 2017 closing price of US $44.88 per common unit on the NYSE, and units held by third parties in Maritimes & Northeast Pipeline, L.L.C., Sabal Trail and Algonquin Gas Transmission, L.L.C., valued based on the underlying net assets of each reporting unit and preferred stock held by third parties in Union Gas and Westcoast Energy Inc. During the third quarter of 2017, we finalized our fair value measurement of Sabal Trail, which resulted in an increase to noncontrolling interests of $85 million as at February 27, 2017. g) We recorded $36.7 billion in goodwill, which is primarily related to expected synergies from the Merger Transaction. The goodwill balance recognized is not deductible for tax purposes. Factors that contributed to the goodwill include the opportunity to expand our natural gas pipelines segment, the potential for cost and supply chain optimization synergies, existing assembled assets and work force that cannot be duplicated at the same cost by a new entrant, franchise rights and other intangibles not separately identifiable because they are inextricably linked to the provision of regulated utility service and the enhanced scale and geographic diversity which provide greater optionality and platforms for future growth. During the third quarter of 2017, goodwill increased by $85 million as at February 27, 2017 due to the finalization of the fair value measurement of Sabal Trail as discussed under (f) above. During the fourth quarter of 2017, goodwill increased by $1,824 million as at February 27, 2017 due to the finalization of the fair value measurement of BC Pipelines & Field Services as discussed under (b) above.
Schedule of Fair Value of Intangible Assets Acquired	The fair value of intangible assets acquired through the Merger Transaction, by major classes is as follows: Weighted Average Fair As at February 27, 2017 Amortization Rate Value (millions of Canadian dollars) Customer relationships 1 3.7 % 739 Project agreement 2 4.0 % 105 Software 11.1 % 329 Other 4.2 % 115 1,288 1 Represents customer relationships in the non-regulated business, which were capitalized upon acquisition. 2 Represents a project agreement between SEP, NextEra Energy, Inc., Duke Energy Corporation (Duke Energy) and Williams Partners L.P. In accordance with the agreement, payments will be made, based on our proportional ownership interest in Sabal Trail, as certain milestones of the project are met. Amortization of the intangible asset began on July 3, 2017 , when Sabal Trail was placed into service (Note 13) .
Schedule of Supplemental Pro Forma Consolidated Financial Information	Our supplemental pro forma consolidated financial information for the year ended December 31, 2017, including the results of operations for Spectra Energy as if the Merger Transaction had been completed on January 1, 2017 are as follows: Year ended December 31, 2017 (unaudited; millions of Canadian dollars) Revenues 45,669 Earnings attributable to common shareholders 1 2,902 1 Merger Transaction costs of $180 million (after-tax $131 million ) were excluded from earnings for the year ended December 31, 2017.
Summary of Net Assets Held for Sale	The table below summarizes the presentation of net assets held for sale in our Consolidated Statements of Financial Position: December 31, 2019 December 31, 2018 2 (millions of Canadian dollars) Accounts receivable and other (current assets held for sale) 28 117 Deferred amounts and other assets (long-term assets held for sale) 1 269 2,383 Accounts payable and other (current liabilities held for sale) — (63 ) Other long-term liabilities (long-term liabilities held for sale) — (96 ) Net assets held for sale 297 2,341 1 Included within Deferred amounts and other assets at December 31, 2019 and 2018 respectively is property, plant and equipment of $181 million and $2.1 billion . 2 Figures are inclusive of net assets held for sale at December 31, 2018 and subsequently disposed of during the year ended December 31, 2019.

ACCOUNTS RECEIVABLE AND OTHER (

ACCOUNTS RECEIVABLE AND OTHER (Tables)	12 Months Ended
	Dec. 31, 2019
Receivables [Abstract]
Schedule of accounts receivable and other	December 31, 2019 2018 (millions of Canadian dollars) Trade receivables and unbilled revenues 1 5,164 4,711 Short-term portion of derivative assets 327 498 Other 1,290 1,308 6,781 6,517 1 Net of allowance for doubtful accounts of $50 million and $64 million as at December 31, 2019 and 2018 , respectively.

INVENTORY (Tables)

INVENTORY (Tables)	12 Months Ended
	Dec. 31, 2019
Inventory Disclosure [Abstract]
Schedule of inventory	December 31, 2019 2018 (millions of Canadian dollars) Natural gas 696 776 Crude oil 542 482 Other commodities 61 81 1,299 1,339

PROPERTY, PLANT AND EQUIPMENT (

PROPERTY, PLANT AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	Weighted Average December 31, Depreciation Rate 2019 2018 1 (millions of Canadian dollars) Pipelines 2.5 % 56,330 51,647 Facilities and equipment 2.7 % 29,287 27,149 Land and right-of-way 2 2.0 % 2,947 2,614 Gas mains, services and other 2.7 % 12,194 12,088 Storage 2.3 % 2,748 2,730 Wind turbines, solar panels and other 4.1 % 4,914 5,015 Other 6.4 % 1,486 1,463 Under construction — % 4,057 9,698 Total property, plant and equipment 3 113,963 112,404 Total accumulated depreciation (20,240 ) (17,864 ) Property, plant and equipment, net 93,723 94,540 1 Asset categories were revised and collapsed in the current year. 2018 comparative figures have been reclassified to conform to current year's asset classifications. 2 The measurement of weighted average depreciation rate excludes non-depreciable assets. 3 Certain assets were reclassified as held for sale as at December 31, 2019 and December 31, 2018 (Note 8) .

VARIABLE INTEREST ENTITIES (Tab

VARIABLE INTEREST ENTITIES (Tables)	12 Months Ended
	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Assets and Liabilities of Consolidated VIEs	The following table includes assets to be used to settle liabilities of our consolidated VIEs and liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit as the primary beneficiary. These assets and liabilities are included in the Consolidated Statements of Financial Position. December 31, 2019 1 2018 (millions of Canadian dollars) Assets Cash and cash equivalents 208 506 Restricted cash 1 61 Accounts receivable and other 76 2,006 Accounts receivable from affiliates — 38 Inventory 4 244 289 2,855 Property, plant and equipment, net 3,392 72,349 Long-term investments 15 6,481 Restricted long-term investments 69 244 Deferred amounts and other assets 4 3,156 Intangible assets, net 124 705 Goodwill — 29 Deferred income taxes — 131 3,893 85,950 Liabilities Short-term borrowings — 275 Accounts payable and other 56 2,925 Accounts payable to affiliates — 4 Interest payable — 303 Environmental liabilities — 22 Current portion of long-term debt — 1,034 56 4,563 Long-term debt — 29,577 Other long-term liabilities 130 5,074 Deferred income taxes 5 6,911 191 46,125 Net assets before noncontrolling interests 3,702 39,825 1 Excludes assets and liabilities of EEP and SEP following the subsidiary guarantees agreement entered on January 22, 2019 (Note 32).
Schedule of the Carrying Amount of Interest in VIEs	The carrying amount of our interest in VIEs that are unconsolidated and our estimated maximum exposure to loss as at December 31, 2019 and 2018 are presented below: Carrying Amount of Investment Enbridge’s Maximum Exposure to December 31, 2019 in VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 1 267 331 Eolien Maritime France SAS 2 67 725 Enbridge Renewable Infrastructure Investments S.a.r.l. 3 141 2,720 Gray Oak Holdings LLC 4 463 935 PennEast Pipeline Company, LLC 5 106 368 Rampion Offshore Wind Limited 6 600 620 Vector Pipeline L.P. 7 195 392 Other 8 57 57 1,896 6,148 Carrying Amount of Investment Enbridge’s Maximum Exposure to December 31, 2018 in VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 1 311 375 Eolien Maritime France SAS 2 68 784 Enbridge Renewable Infrastructure Investments S.a.r.l. 3 127 3,037 Illinois Extension Pipeline Company, L.L.C. 8 724 724 NEXUS Gas Transmission, LLC 9 1,757 2,668 PennEast Pipeline Company, LLC 5 97 385 Rampion Offshore Wind Limited 6 638 648 Vector Pipeline L.P. 7 198 301 Other 8 27 27 3,947 8,949 1 At December 31, 2019 and 2018, the maximum exposure to loss includes a guarantee issued by us for our respective share of the VIE’s borrowing on a bank credit facility. 2 At December 31, 2019 and 2018, the maximum exposure to loss includes the portion of our parental guarantee that has been committed in project construction contracts for which we would be liable in the event of default by the VIE and an outstanding affiliate loan receivable for $166 million and $202 million held by us as at December 31, 2019 and 2018, respectively. 3 At December 31, 2019 and 2018, the maximum exposure to loss includes the portion of our parental guarantee that has been committed in project construction contracts for which we would be liable in the event of default by the VIE and an outstanding affiliate loan receivable for $766 million and $461 million held by us as at December 31, 2019 and 2018, respectively. 4 At December 31, 2019 , the maximum exposure to loss includes our portion of project construction costs. 5 At December 31, 2019 and 2018, the maximum exposure to loss includes the remaining expected contributions to the joint venture. 6 At December 31, 2019 and 2018, the maximum exposure to loss includes the portion of our parental guarantee that has been committed in project construction contracts for which we would be liable in the event of default by the VIE. 7 At December 31, 2019 and 2018, the maximum exposure to loss includes the carrying value of an outstanding affiliate loan receivable for $92 million and $102 million held by us as at December 31, 2019 and 2018, respectively, in addition to us providing a credit facility for $105 million as at December 31, 2019. 8 At December 31, 2019 and 2018, the maximum exposure to loss is limited to our equity investment as these companies are in operation and self-sustaining. 9 As at December 31, 2018, the maximum exposure to loss includes the remaining expected contributions to the joint venture and parental guarantees for our portion of capacity lease agreements.

LONG-TERM INVESTMENTS (Tables)

LONG-TERM INVESTMENTS (Tables)	12 Months Ended
	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Long-Term Investments	Ownership December 31, Interest 2019 2018 (millions of Canadian dollars) EQUITY INVESTMENTS Liquids Pipelines MarEn Bakken Company L.L.C. 1 75.0 % 1,892 2,039 Gray Oak Holdings L.L.C. 2 35.0 % 463 — Seaway Crude Pipeline System 50.0 % 2,907 3,113 Illinois Extension Pipeline Company, L.L.C. 3 65.0 % 662 724 Other 30.0% - 43.8% 73 97 Gas Transmission and Midstream Alliance Pipeline 50.0 % 310 368 Aux Sable 42.7% - 50.0% 267 311 DCP Midstream, LLC 50.0 % 2,193 2,368 Gulfstream Natural Gas System, L.L.C. 50.0 % 1,213 1,289 NEXUS Gas Transmission, LLC 50.0 % 1,778 1,757 Offshore - various joint ventures 22.0% - 74.3% 362 400 PennEast Pipeline Company LLC 20.0 % 106 97 Sabal Trail Transmission, LLC 50.0 % 1,533 1,586 Southeast Supply Header L.L.C. 50.0 % 484 519 Steckman Ridge LP 49.5 % 222 237 Vector Pipeline L.P. 60.0 % 195 198 Other 33.3% - 50.0% 5 6 Gas Distribution and Storage Noverco Common Shares 38.9 % 95 — Other 50.0 % 14 15 Renewable Power Generation Eolien Maritime France SAS 50.0 % 67 68 Enbridge Renewable Infrastructure Investments S.a.r.l. 4 51.0 % 141 127 Rampion Offshore Wind Project 24.9 % 600 638 Other 21.0% - 50.0% 127 72 Eliminations and Other Other 42.7% - 50% 16 10 OTHER LONG-TERM INVESTMENTS Gas Distribution and Storage Noverco Preferred Shares 580 478 Renewable Power Generation Emerging Technologies and Other 78 80 Eliminations and Other Other 145 110 16,528 16,707 1 Owns 49% interest in Bakken Pipeline Investments L.L.C., which owns 75% of the Bakken Pipeline System resulting in a 27.6% effective interest in the Bakken Pipeline System. 2 In December 2018 we acquired an effective 22.8% interest in the Gray Oak crude oil pipeline through acquisition of a 35% membership interest in Gray Oak Holdings, L.L.C. (Note 12). 3 Owns the Southern Access Extension Project. 4 In 2018 we sold a 49% interest in the Hohe See Offshore wind facilities to CPPIB, reducing our effective interest in the project to 25.5% .
Summary of Combined Financial Information	Summarized combined financial information of our interest in unconsolidated equity investments (presented at 100%) is as follows: Year Ended December 31, 2019 2018 2017 Seaway Other Total Seaway Other Total Seaway Other Total (millions of Canadian dollars) Operating revenues 1,252 14,435 15,687 966 18,251 19,217 959 15,254 16,213 Operating expenses 428 12,725 13,153 212 15,422 15,634 286 12,911 13,197 Earnings 818 2,198 3,016 646 2,308 2,954 672 2,056 2,728 Earnings attributable to Enbridge 409 950 1,359 323 1,059 1,382 336 926 1,262 December 31, 2019 December 31, 2018 Seaway Other Total Seaway Other Total (millions of Canadian dollars) Current assets 107 2,374 2,481 113 3,176 3,289 Non-current assets 3,404 45,538 48,942 3,585 45,531 49,116 Current liabilities 136 3,911 4,047 123 5,413 5,536 Non-current liabilities 45 18,081 18,126 16 15,859 15,875 Noncontrolling interests — 2,779 2,779 — 3,479 3,479

INTANGIBLE ASSETS (Tables)

INTANGIBLE ASSETS (Tables)	12 Months Ended
	Dec. 31, 2019
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Schedule of intangible assets	The following table provides the weighted average amortization rate, gross carrying value, accumulated amortization and net carrying value for each of our major classes of intangible assets: Weighted Average Accumulated December 31, 2019 1 Amortization Rate Cost Amortization Net (millions of Canadian dollars) Customer relationships 5.4 % 861 (231 ) 630 Power purchase agreements 4.5 % 64 (16 ) 48 Project agreement 2 4.0 % 156 (16 ) 140 Software 11.2 % 1,988 (1,014 ) 974 Other intangible assets 3 2.9 % 463 (82 ) 381 3,532 (1,359 ) 2,173 Weighted Average Accumulated December 31, 2018 1 Amortization Rate Cost Amortization Net (millions of Canadian dollars) Customer relationships 5.7 % 889 (187 ) 702 Power purchase agreements 5.4 % 82 (15 ) 67 Project agreement 2 4.0 % 164 (10 ) 154 Software 10.0 % 1,902 (875 ) 1,027 Other intangible assets 3 2.0 % 485 (63 ) 422 3,522 (1,150 ) 2,372 1 Certain assets were reclassified as held for sale as at December 31, 2019 and December 31, 2018 (Note 8) . 2 Represents a project agreement acquired from the Merger Transaction (Note 8) . 3 The measurement of weighted average amortization rate excludes non-depreciable intangible assets.
Schedule of future amortization expense	The following table presents our expected amortization expense associated with existing intangible assets for the years indicated as follows: 2020 2021 2022 2023 2024 Forecast of amortization expense (millions of Canadian dollars) 292 263 238 216 195

GOODWILL (Tables)

GOODWILL (Tables)	12 Months Ended
	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of goodwill	Liquids Pipelines Gas Gas Renewable Power Generation Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Gross Cost Balance at January 1, 2018 7,786 21,539 5,679 — 2 13 35,019 Disposition — (628 ) — — — — (628 ) Allocation to assets held for sale — (55 ) (133 ) — — — (188 ) Foreign exchange and other 538 1,482 (183 ) — — — 1,837 Balance at December 31, 2018 8,324 22,338 5,363 — 2 13 36,040 Foreign exchange and other (373 ) (933 ) — — — — (1,306 ) Balance at December 31, 2019 7,951 21,405 5,363 — 2 13 34,734 Accumulated Impairment Balance at January 1, 2018 — (542 ) (7 ) — — (13 ) (562 ) Impairment — (1,019 ) — — — — (1,019 ) Balance at December 31, 2018 — (1,561 ) (7 ) — — (13 ) (1,581 ) Balance at December 31, 2019 — (1,561 ) (7 ) — — (13 ) (1,581 ) Carrying Value Balance at December 31, 2018 8,324 20,777 5,356 — 2 — 34,459 Balance at December 31, 2019 7,951 19,844 5,356 — 2 — 33,153

ACCOUNTS PAYABLE AND OTHER (Tab

ACCOUNTS PAYABLE AND OTHER (Tables)	12 Months Ended
	Dec. 31, 2019
Payables and Accruals [Abstract]
Schedule of accounts payable and other	December 31, 2019 2018 (millions of Canadian dollars) Trade payables and operating accrued liabilities 4,536 4,604 Construction payables and contractor holdbacks 804 804 Current derivative liabilities 920 1,234 Dividends payable 1,678 1,539 Taxes payable 890 801 Current deferred credits 652 850 Other 583 31 10,063 9,863

DEBT (Tables)

DEBT (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Schedule of Debt	Weighted Average December 31, Interest Rate 22 Maturity 2019 2018 (millions of Canadian dollars) Enbridge Inc. United States dollar senior notes 1 3.8 % 2022-2049 8,689 6,419 Medium-term notes 4.2 % 2020-2064 7,623 7,323 Fixed-to-floating rate subordinated term notes 2,3 5.9 % 2077-2078 6,550 6,771 Floating rate notes 4 2020 1,556 2,389 Commercial paper and credit facility draws 5 1.9 % 2021-2024 5,210 1,999 Other 6 5 4 Enbridge (U.S.) Inc. Commercial paper and credit facility draws 7 2.1 % 2021-2024 1,734 1,065 Enbridge Energy Partners, L.P. Senior notes 8 6.0 % 2021-2045 3,955 6,214 Junior subordinated notes 9 — 546 Commercial paper and credit facility draws 10 — 1,044 Enbridge Gas Distribution Inc. 11 Medium-term notes — 3,695 Debentures — 85 Commercial paper and credit facility draws — 750 Enbridge Gas Inc. 11 Medium-term notes 4.2 % 2020-2050 7,685 — Debentures 9.1 % 2024-2025 210 — Commercial paper and credit facility draws 2.0 % 2021 898 — Enbridge Pipelines (Southern Lights) L.L.C. Senior notes 12 4.0 % 2040 1,129 1,257 Enbridge Pipelines Inc. Medium-term notes 13 4.2 % 2020-2049 5,125 4,225 Debentures 8.2 % 2024 200 200 Commercial paper and credit facility draws 14 2.0 % 2021 2,030 2,200 Enbridge Southern Lights LP Senior notes 4.0 % 2040 272 289 Spectra Energy Capital, LLC Senior notes 15 7.1 % 2032-2038 224 236 Spectra Energy Partners, LP Senior secured notes 16 6.1 % 2020 143 150 Senior notes 17 4.2 % 2020-2048 8,481 8,249 Floating rate notes 18 2020 519 546 Commercial paper and credit facility draws 19 — 2,065 Union Gas Limited 11 Medium-term notes — 3,290 Debentures — 125 Commercial paper and credit facility draws — 275 Westcoast Energy Inc. Senior secured notes — 33 Medium-term notes 4.5 % 2020-2041 1,875 2,175 Debentures 8.6 % 2020-2026 375 375 Fair value adjustment - Merger Transaction 844 964 Other 20 (369 ) (348 ) Total debt 64,963 64,610 Current maturities (4,404 ) (3,259 ) Short-term borrowings 21 (898 ) (1,024 ) Long-term debt 59,661 60,327 1 2019 - US $6,700 million ; 2018 - US $4,700 million . 2 2019 - $2,400 million and US $3,200 million ; 2018 - $2,400 million and US $3,200 million . For the initial 10 years , the notes carry a fixed interest rate. Subsequently, the interest rate will be floating and set to equal the Canadian Dollar Offered Rate (CDOR) or the London Interbank Offered Rate (LIBOR) plus a margin. 3 The notes would be converted automatically into Conversion Preference Shares in the event of bankruptcy and related events. 4 2019 - US $1,200 million ; 2018 - $750 million and US $1,200 million . Carries an interest rate equal to the three-month Bankers' Acceptance Rate plus a margin of 59 basis points or LIBOR plus a margin of 40 or 70 basis points. 5 2019 - $5,210 million ; 2018 - $1,906 million and US $69 million . 6 Primarily capital lease obligations. 7 2019 - US $1,337 million ; 2018 - US $780 million . 8 2019 - US $3,050 million ; 2018 - US $4,550 million . 9 2018 - US $400 million . 10 2018 - US $764 million . 11 Reflects the amalgamation of EGD and Union Gas into Enbridge Gas Inc . 12 2019 - US $871 million ; 2018 - US $920 million . 13 Included in medium-term notes is $100 million with a maturity date of 2112. 14 2019 - $1,570 million and US $355 million ; 2018 - $1,905 million and US $216 million . 15 2019 - US $173 million ; 2018 - US $173 million . 16 2019 - US $110 million ; 2018 - US $110 million . 17 2019 - US $6,540 million ; 2018 - US $6,040 million . 18 2019 - US $400 million ; 2018 - US $400 million . Carries an interest rate equal to the three-month LIBOR plus a margin of 70 basis points. 19 2018 - US $1,512 million . 20 Primarily unamortized discounts and debt issuance costs. 21 Weighted average interest rates on outstanding commercial paper were 2.0% as at December 31, 2019 ( 2018 - 2.3% ). 22 Calculated based on term notes and commercial paper and credit facility draws balances outstanding as at December 31, 2019 .
Schedule of Committed Credit Facilities	The following table provides details of our committed credit facilities as at December 31, 2019 : Total Maturity Facilities Draws 1 Available (millions of Canadian dollars) Enbridge Inc. 2021-2024 6,993 5,210 1,783 Enbridge (U.S.) Inc. 2021-2024 7,132 1,734 5,398 Enbridge Pipelines Inc. 2021 2 3,000 2,030 970 Enbridge Gas Inc. 2021 2 2,000 898 1,102 Total committed credit facilities 19,125 9,872 9,253 1 Includes facility draws and commercial paper issuances that are back-stopped by the credit facility. 2 Maturity date is inclusive of the one year term out option.
Schedule of Long-term Debt Issuances	During the years ended December 31, 2019 and 2018 , we completed the following long-term debt issuances, excluding the debt exchange discussed below: Company Issue Date Principal Amount (millions of Canadian dollars unless otherwise stated) Enbridge Inc. October 2019 2.99% medium-term notes due October 2029 $1,000 November 2019 2.50% senior notes due July 2025 US$500 November 2019 3.13% senior notes due November 2029 US$1,000 November 2019 4.00% senior notes due November 2049 US$500 March 2018 Fixed-to-floating rate subordinated notes due March 2078 1 US$850 April 2018 Fixed-to-floating rate subordinated notes due April 2078 2 $750 April 2018 Fixed-to-floating rate subordinated notes due April 2078 3 US$600 Enbridge Gas Inc. August 2019 2.37% medium-term notes due August 2029 $400 August 2019 3.01% medium-term notes due August 2049 $300 Enbridge Pipelines Inc. February 2019 3.52% medium-term notes due February 2029 $600 February 2019 4.33% medium-term notes due February 2049 $600 Spectra Energy Partners, LP August 2019 3.24% senior notes due August 2029 4 US$500 January 2018 3.50% senior notes due January 2028 5 US$400 January 2018 4.15% senior notes due January 2048 5 US$400 1 Notes mature in 60 years and are callable on or after year 10 . For the initial 10 years , the notes carry a fixed interest rate of 6.25% . Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 364 basis points from years 10 to 30 , and a margin of 439 basis points from years 30 to 60 . 2 Notes mature in 60 years and are callable on or after year 10 . For the initial 10 years , the notes carry a fixed interest rate of 6.625% . Subsequently, the interest rate will be set to equal CDOR plus a margin of 432 basis points from years 10 to 30 , and a margin of 507 basis points from years 30 to 60 . 3 Notes mature in 60 years and are callable on or after year five . For the initial five years , the notes carry a fixed interest rate of 6.375% . Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 359 basis points from years five to 10 , a margin of 384 basis points from years 10 to 25 , and a margin of 459 basis points from years 25 to 60 . 4 Issued through Algonquin Gas Transmission, LLC, an operating subsidiary of SEP. 5 Issued through Texas Eastern, a wholly-owned operating subsidiary of SEP. Consenting SEP notes and EEP notes under Guarantee SEP Notes 1 EEP Notes 2 Floating Rate Senior Notes due 2020 4.200% Notes due 2021 4.600% Senior Notes due 2021 5.875% Notes due 2025 4.750% Senior Notes due 2024 5.950% Notes due 2033 3.500% Senior Notes due 2025 6.300% Notes due 2034 3.375% Senior Notes due 2026 7.500% Notes due 2038 5.950% Senior Notes due 2043 5.500% Notes due 2040 4.500% Senior Notes due 2045 7.375% Notes due 2045 1 As at December 31, 2019 , the aggregate outstanding principal amount of SEP notes was approximately US $3.9 billion . 2 As at December 31, 2019 , the aggregate outstanding principal amount of EEP notes was approximately US $3.0 billion . Enbridge Notes under Guarantees USD Denominated 1 CAD Denominated 2 Senior Floating Rate Notes due 2020 4.530% Senior Notes due 2020 Senior Floating Rate Notes due 2020 4.850% Senior Notes due 2020 2.900% Senior Notes due 2022 4.260% Senior Notes due 2021 4.000% Senior Notes due 2023 3.160% Senior Notes due 2021 3.500% Senior Notes due 2024 4.850% Senior Notes due 2022 2.500% Senior Notes due 2025 3.190% Senior Notes due 2022 4.250% Senior Notes due 2026 3.940% Senior Notes due 2023 3.700% Senior Notes due 2027 3.940% Senior Notes due 2023 3.125% Senior Notes due 2029 3.950% Senior Notes due 2024 4.500% Senior Notes due 2044 3.200% Senior Notes due 2027 5.500% Senior Notes due 2046 6.100% Senior Notes due 2028 4.000% Senior Notes due 2049 2.990% Senior Notes due 2029 7.220% Senior Notes due 2030 7.200% Senior Notes due 2032 5.570% Senior Notes due 2035 5.750% Senior Notes due 2039 5.120% Senior Notes due 2040 4.240% Senior Notes due 2042 4.570% Senior Notes due 2044 4.870% Senior Notes due 2044 4.560% Senior Notes due 2064 1 As at December 31, 2019 , the aggregate outstanding principal amount of the Enbridge United States dollar denominated notes was approximately US $7.9 billion . 2 As at December 31, 2019 , the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was approximately $7.6 billion .
Schedule of Long-Term Debt Repayments	During the years ended December 31, 2019 and 2018 , we completed the following long-term debt repayments, excluding the debt exchange discussed below: Company Retirement/Repayment Date Principal Amount Cash Consideration 1 (millions of Canadian dollars unless otherwise stated) Enbridge Inc. Repayment February 2019 4.10% medium-term notes $300 May 2019 Floating rate notes $750 September 2019 4.77% medium-term notes $400 Enbridge Energy Partners, L.P. Redemption February 2019 8.05% fixed/floating rate junior subordinated notes due 2067 US$400 December 2019 5.20% senior notes due 2020 US$500 US$504 December 2019 4.38% senior notes due 2020 US$500 US$509 Repayment March 2019 9.88% senior notes US$500 April 2018 6.50% senior notes US$400 October 2018 7.00% senior notes US$100 Enbridge Income Fund Repayment December 2018 4.00% medium-term notes $125 Enbridge Pipelines (Southern Lights) L.L.C. Repayment June and December 2019 3.98% senior notes due 2040 US$49 June and December 2018 3.98% senior notes due 2040 US$43 Enbridge Pipelines Inc. Repayment November 2019 4.49% medium-term notes $200 November 2019 4.49% medium-term notes $100 November 2018 6.62% medium-term notes $170 November 2018 6.62% medium-term notes $130 Enbridge Southern Lights LP Repayment July and December 2019 4.01% senior notes due 2040 $17 January, July and December 2018 4.01% senior notes due 2040 $27 Midcoast Energy Partners, L.P. Redemption July 2018 2 3.56% senior notes due 2019 US$75 US$76 July 2018 2 4.04% senior notes due 2021 US$175 US$182 July 2018 2 4.42% senior notes due 2024 US$150 US$161 Spectra Energy Capital, LLC Repurchase via Tender Offer March 2018 2 6.75% senior unsecured notes due 2032 US$64 US$80 March 2018 2 7.50% senior unsecured notes due 2038 US$43 US$59 Redemption March 2018 2 5.65% senior unsecured notes due 2020 US$163 US$172 March 2018 2 3.30% senior unsecured notes due 2023 US$498 US$508 Repayment April 2018 6.20% senior notes US$272 July 2018 6.75% senior notes US$118 Spectra Energy Partners, LP Repayment September 2018 2.95% senior notes US$500 Union Gas Limited Repayment April 2018 5.35% medium-term notes $200 August 2018 8.75% debentures $125 October 2018 8.65% senior debentures $75 Westcoast Energy Inc. Repayment January 2019 5.60% medium-term notes $250 January 2019 5.60% medium-term notes $50 May and November 2019 6.90% senior secured notes $26 May and November 2019 4.34% senior secured notes $5 December 2019 1.00% senior secured notes $2 May and November 2018 6.90% senior secured notes due 2019 $26 May and November 2018 4.34% senior secured notes due 2019 $9 September 2018 8.50% debentures $150 1 Cash consideration disclosed for repayments where the cash paid differs from the principal amount. 2 The loss on debt extinguishment of $64 million (US $50 million ), net of the fair value adjustment recorded upon completion of the Merger Transaction, was reported within Interest expense in the Consolidated Statements of Earnings.
Schedule of Interest Expense	INTEREST EXPENSE Year ended December 31, 2019 2018 2017 (millions of Canadian dollars) Debentures and term notes 2,783 3,011 3,011 Commercial paper and credit facility draws 273 171 206 Amortization of fair value adjustment - Spectra Energy acquisition (67 ) (131 ) (270 ) Capitalized (326 ) (348 ) (391 ) 2,663 2,703 2,556

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Reconciliation of movements in the Company's ARO	A reconciliation of movements in our ARO liabilities is as follows: December 31, 2019 2018 (millions of Canadian dollars) Obligations at beginning of year 989 793 Liabilities acquired — — Liabilities disposed (59 ) (13 ) Liabilities incurred 15 145 Liabilities settled (12 ) (21 ) Change in estimate and other (417 ) 29 Foreign currency translation adjustment (18 ) 22 Accretion expense 22 34 Obligations at end of year 520 989 Presented as follows: Accounts payable and other 7 6 Other long-term liabilities 513 983 520 989

NONCONTROLLING INTERESTS (Table

NONCONTROLLING INTERESTS (Tables)	12 Months Ended
	Dec. 31, 2019
Noncontrolling Interest [Abstract]
Schedule of noncontrolling interests	The following table provides additional information regarding Noncontrolling interests as presented in our Consolidated Statements of Financial Position: December 31, 2019 2018 (millions of Canadian dollars) Algonquin Gas Transmission, L.L.C 394 518 Maritimes & Northeast Pipeline, L.L.C 579 613 Renewable energy assets 1 1,864 1,961 Westcoast Energy Inc. 2 527 841 Other — 32 3,364 3,965 1 On August 1, 2018, we closed the sale of 49% of our interest in the Renewable Assets (Note 8) . The remaining balance represents the tax equity investors' interests in Magic Valley, Wildcat, Keechi, New Creek and Chapman Ranch wind facilities, with an additional 20.0% noncontrolling interest in each of the Magic Valley and Wildcat wind facilities held by third parties as at December 31, 2019 and 2018 . 2 Represents the 16.6 million cumulative redeemable preferred shares as at December 31, 2019 and 2018, nil and 12 million cumulative first preferred shares as at December 31, 2019 and 2018, respectively, held by third parties in Westcoast Energy Inc., in addition to the 22.2% interest in Maritimes & Northeast Pipeline Limited Partnership held by third parties as at December 31, 2019 and 2018.
Schedule of redeemable noncontrolling interests	The following table presents additional information regarding Redeemable noncontrolling interests as presented in our Consolidated Statements of Financial Position: Year ended December 31, 2018 2017 (millions of Canadian dollars) Balance at beginning of year 4,067 3,392 Earnings attributable to redeemable noncontrolling interests 117 175 Other comprehensive income/(loss), net of tax Change in unrealized loss on cash flow hedges 3 (21 ) Other comprehensive loss from equity investees 14 — Reclassification to earnings of loss on cash flow hedges — 57 Foreign currency translation adjustments 4 (6 ) Other comprehensive income/(loss), net of tax 21 30 Distributions to unitholders (300 ) (247 ) Contributions from unitholders 70 1,178 Modified retrospective adoption of accounting standard (38 ) — Net dilution gain/(loss) 76 (169 ) Redemption value adjustment 456 (292 ) Sponsored vehicle buy-in 1 (4,469 ) — Balance at end of year — 4,067 1 On November 8, 2018, we executed the definitive agreement with ENF and acquired all of the publicly held shares of ENF not already owned by us or our subsidiaries.

SHARE CAPITAL (Tables)

SHARE CAPITAL (Tables)	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Schedule of common shares	COMMON SHARES 2019 2018 2017 Number Number Number December 31, of Shares Amount of Shares Amount of Shares Amount (millions of Canadian dollars; number of shares in millions) Balance at beginning of year 2,022 64,677 1,695 50,737 943 10,492 Common shares issued — — — — 33 1,500 Common shares issued in Merger Transaction (Note 8) — — — — 691 37,429 Common shares issued in Sponsored Vehicle buy-in (SEP) (Note 20) — — 91 3,888 — — Common shares issued in Sponsored Vehicle buy-in (EEP) (Note 20) — — 72 3,042 — — Common shares issued in Sponsored Vehicle buy-in (EEM) (Note 20) — — 30 1,267 — — Common shares issued in Sponsored Vehicle buy-in (ENF) (Note 20) — — 104 4,530 — — Dividend Reinvestment and Share Purchase Plan — — 28 1,181 25 1,226 Shares issued on exercise of stock options 3 69 2 32 3 90 Balance at end of year 2,025 64,746 2,022 64,677 1,695 50,737
Schedule of preference shares	PREFERENCE SHARES 2019 2018 2017 Number Number Number December 31, of Shares Amount of Shares Amount of Shares Amount (millions of Canadian dollars; number of shares in millions) Preference Shares, Series A 5 125 5 125 5 125 Preference Shares, Series B 18 457 18 457 18 457 Preference Shares, Series C 2 43 2 43 2 43 Preference Shares, Series D 18 450 18 450 18 450 Preference Shares, Series F 20 500 20 500 20 500 Preference Shares, Series H 14 350 14 350 14 350 Preference Shares, Series J 8 199 8 199 8 199 Preference Shares, Series L 16 411 16 411 16 411 Preference Shares, Series N 18 450 18 450 18 450 Preference Shares, Series P 16 400 16 400 16 400 Preference Shares, Series R 16 400 16 400 16 400 Preference Shares, Series 1 16 411 16 411 16 411 Preference Shares, Series 3 24 600 24 600 24 600 Preference Shares, Series 5 8 206 8 206 8 206 Preference Shares, Series 7 10 250 10 250 10 250 Preference Shares, Series 9 11 275 11 275 11 275 Preference Shares, Series 11 20 500 20 500 20 500 Preference Shares, Series 13 14 350 14 350 14 350 Preference Shares, Series 15 11 275 11 275 11 275 Preference Shares, Series 17 30 750 30 750 30 750 Preference Shares, Series 19 20 500 20 500 20 500 Issuance costs (155 ) (155 ) (155 ) Balance at end of year 7,747 7,747 7,747
Schedule of characteristics of preference shares	Characteristics of the preference shares are as follows: Dividend Rate Dividend 1 Per Share Base Redemption Value 2 Redemption and Conversion Option Date 2,3 Right to Convert Into 3,4 (Canadian dollars unless otherwise stated) Preference Shares, Series A 5.50 % $1.37500 $25 — — Preference Shares, Series B 3.42 % $0.85360 $25 June 1, 2022 Series C Preference Shares, Series C 5 3-month treasury bill plus 2.40% — $25 June 1, 2022 Series B Preference Shares, Series D 4.46 % $1.11500 $25 March 1, 2023 Series E Preference Shares, Series F 4.69 % $1.17224 $25 June 1, 2023 Series G Preference Shares, Series H 4.38 % $1.09400 $25 September 1, 2023 Series I Preference Shares, Series J 4.89 % US$1.22160 US$25 June 1, 2022 Series K Preference Shares, Series L 4.96 % US$1.23972 US$25 September 1, 2022 Series M Preference Shares, Series N 5.09 % $1.27152 $25 December 1, 2023 Series O Preference Shares, Series P 6 4.38 % $1.09476 $25 March 1, 2024 Series Q Preference Shares, Series R 6 4.07 % $1.01825 $25 June 1, 2024 Series S Preference Shares, Series 1 5.95 % US$1.48728 US$25 June 1, 2023 Series 2 Preference Shares, Series 3 6 3.74 % $0.93425 $25 September 1, 2024 Series 4 Preference Shares, Series 5 6 5.38 % US$1.34383 US$25 March 1, 2024 Series 6 Preference Shares, Series 7 6 4.45 % $1.11224 $25 March 1, 2024 Series 8 Preference Shares, Series 9 6 4.10 % $1.02424 $25 December 1, 2024 Series 10 Preference Shares, Series 11 4.40 % $1.10000 $25 March 1, 2020 Series 12 Preference Shares, Series 13 4.40 % $1.10000 $25 June 1, 2020 Series 14 Preference Shares, Series 15 4.40 % $1.10000 $25 September 1, 2020 Series 16 Preference Shares, Series 17 5.15 % $1.28750 $25 March 1, 2022 Series 18 Preference Shares, Series 19 4.90 % $1.22500 $25 March 1, 2023 Series 20 1 The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend, as declared by the Board of Directors. With the exception of Series A and Series C Preference Shares, such fixed dividend rate resets every five years beginning on the initial redemption and conversion option date. The Series 17 and Series 19 Preference Shares contain a feature where the fixed dividend rate, when reset every five years , will not be less than 5.15% and 4.90% , respectively. No other series of Preference Shares has this feature. 2 Series A Preference Shares may be redeemed any time at our option. For all other series of Preference Shares, we, may at our option, redeem all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter. 3 The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on a one -for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an ascribed issue price equal to the Base Redemption Value. 4 With the exception of Series A Preference Shares, after the redemption and conversion option dates, holders may elect to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/ 365 ) x 90 day Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q), 2.5% (Series S), 2.4% (Series 4), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7% (Series 16), 4.1% (Series 18) or 3.2% (Series 20); or US $25 x (number of days in quarter/ 365 ) x three -month United States Government treasury bill rate + 3.1% (Series K), 3.2% (Series M), 3.1% (Series 2) or 2.8% (Series 6). 5 The floating quarterly dividend amount for the Series C Preference Shares was decreased to $0.25395 from $0.25459 on March 1, 2019, was increased to $0.25647 from $0.25395 on June 1, 2019, was decreased to $0.25243 from $0.25647 on September 1, 2019 and was increased to $0.25305 from $0.25243 on December 1, 2019, due to reset on a quarterly basis following the issuance thereof. 6 No Series P, R, 3, 5, 7 or 9 Preference shares were converted on the March 1, 2019, June 1, 2019, September 1, 2019, March 1, 2019, March 1, 2019 or December 1, 2019 conversion option dates, respectively. However, the quarterly dividend amounts for Series P, R, 3, 5, 7 or 9, was increased to $0.27369 from $0.25000 on March 1, 2019, increased to $0.25456 from $0.25000 on June 1, 2019, decreased to $0.23356 from $0.25000 on September 1, 2019, increased to US $0.33625 from US $0.27500 on March 1, 2019, increased to $0.27806 from $0.27500 on March 1, 2019 and decreased to $0.25606 from $0.27500 on December 1, 2019, respectively, due to reset on every fifth anniversary thereafter.

STOCK OPTION AND STOCK UNIT P_2

STOCK OPTION AND STOCK UNIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2019
STOCK OPTION AND STOCK UNIT PLANS
Share-based Payment Arrangement, Performance Shares, Activity [Table Text Block]	December 31, 2019 Number Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 1,069 Units granted 1,093 Units cancelled (65 ) Units matured 1 (25 ) Dividend reinvestment 117 Units outstanding at end of year 2,189 1.5 111 1 The total amount paid during the years ended December 31, 2019 , 2018 and 2017 for PSUs was $19 million , $18 million and $28 million , respectively.
INCENTIVE STOCK OPTIONS
STOCK OPTION AND STOCK UNIT PLANS
Schedule of outstanding stock options	December 31, 2019 Number Weighted Average Exercise Price Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (options in thousands; intrinsic value in millions of Canadian dollars) Options outstanding at beginning of year 34,387 43.47 Options granted 6,777 48.32 Options exercised 1 (4,519 ) 34.19 Options cancelled or expired (1,598 ) 50.62 Options outstanding at end of year 35,047 47.73 6.2 157 Options vested at end of year 2 20,581 47.67 4.7 92 1 The total intrinsic value of ISOs exercised during the years ended December 31, 2019 , 2018 and 2017 was $58 million , $42 million and $62 million , respectively, and cash received on exercise was $1 million , $15 million and $17 million , respectively. 2 The total fair value of ISOs vested during the years ended December 31, 2019 , 2018 and 2017 was $32 million , $36 million and $44 million , respectively.
Schedule of weighted average assumptions used to determine the fair value of stock options granted	Weighted average assumptions used to determine the fair value of ISOs granted using the Black-Scholes-Merton option pricing model are as follows: Year ended December 31, 2019 2018 2017 Fair value per option (Canadian dollars) 1 4.37 3.86 6.00 Valuation assumptions Expected option term (years) 2 5 5 5 Expected volatility 3 19.9 % 21.9 % 20.4 % Expected dividend yield 4 6.1 % 6.4 % 4.4 % Risk-free interest rate 5 2.0 % 2.2 % 1.2 % 1 Options granted to United States employees are based on NYSE prices. The option value and assumptions shown are based on a weighted average of the United States and the Canadian options. The fair values per option for the years ended December 31, 2019 , 2018 and 2017 were $4.04 , $3.75 and $5.66 , respectively, for Canadian employees and US $4.09 , US $3.30 and US $5.72 , respectively, for United States employees. 2 The expected option term is six years based on historical exercise practice and three years for retirement eligible employees. 3 Expected volatility is determined with reference to historic daily share price volatility and consideration of the implied volatility observable in call option values near the grant date. 4 The expected dividend yield is the current annual dividend at the grant date divided by the current stock price. 5 The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields and the United States Treasury Bond Yields.
Restricted Stock Units (RSU)
STOCK OPTION AND STOCK UNIT PLANS
Schedule of outstanding stock units	December 31, 2019 Number Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 1,213 Units granted 1,087 Units cancelled (96 ) Units matured 1 (706 ) Dividend reinvestment 126 Units outstanding at end of year 1,624 1.6 82 1 The total amount paid during the years ended December 31, 2019 , 2018 and 2017 for RSUs was $34 million , $41 million and $39 million , respectively.

COMPONENTS OF ACCUMULATED OTH_2

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) (Tables)	12 Months Ended
	Dec. 31, 2019
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Schedule of changes in AOCI attributable to Enbridge common shareholders	Changes in AOCI attributable to our common shareholders for the years ended December 31, 2019 , 2018 and 2017 are as follows: Cash Flow Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance at January 1, 2019 (770 ) (598 ) 4,323 34 (317 ) 2,672 Other comprehensive income/(loss) retained in AOCI (599 ) 320 (2,927 ) 34 (124 ) (3,296 ) Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 157 — — — — 157 Commodity contracts 2 (1 ) — — — — (1 ) Foreign exchange contracts 3 5 — — — — 5 Other contracts 4 (3 ) — — — — (3 ) Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 17 17 (441 ) 320 (2,927 ) 34 (107 ) (3,121 ) Tax impact Income tax on amounts retained in AOCI 169 (39 ) — 6 28 164 Income tax on amounts reclassified to earnings (31 ) — — — (4 ) (35 ) 138 (39 ) — 6 24 129 Other — — — (7 ) 55 48 Balance at December 31, 2019 (1,073 ) (317 ) 1,396 67 (345 ) (272 ) Cash Flow Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance at January 1, 2018 (644 ) (139 ) 77 10 (277 ) (973 ) Other comprehensive income/(loss) retained in AOCI (244 ) (509 ) 4,301 16 (85 ) 3,479 Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 157 — — — — 157 Commodity contracts 2 (1 ) — — — — (1 ) Foreign exchange contracts 3 7 — — — — 7 Other contracts 4 22 — — — — 22 Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 16 16 (59 ) (509 ) 4,301 16 (69 ) 3,680 Tax impact Income tax on amounts retained in AOCI 57 50 — 8 33 148 Income tax on amounts reclassified to earnings (37 ) — — — (4 ) (41 ) 20 50 — 8 29 107 Sponsored Vehicles buy-in 6 (87 ) — (55 ) — — (142 ) Balance at December 31, 2018 (770 ) (598 ) 4,323 34 (317 ) 2,672 Cash Flow Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance at January 1, 2017 (746 ) (629 ) 2,700 37 (304 ) 1,058 Other comprehensive income/(loss) retained in AOCI 1 478 (2,623 ) (11 ) 18 (2,137 ) Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 207 — — — — 207 Commodity contracts 2 (7 ) — — — — (7 ) Foreign exchange contracts 3 (6 ) — — — — (6 ) Other contracts 4 (6 ) — — — — (6 ) Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 41 41 189 478 (2,623 ) (11 ) 59 (1,908 ) Tax impact Income tax on amounts retained in AOCI (16 ) 12 — (16 ) (10 ) (30 ) Income tax on amounts reclassified to earnings (71 ) — — — (22 ) (93 ) (87 ) 12 — (16 ) (32 ) (123 ) Balance at December 31, 2017 (644 ) (139 ) 77 10 (277 ) (973 ) 1 Reported within Interest expense in the Consolidated Statements of Earnings. 2 Reported within Transportation and other services revenue, Commodity sales revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. 3 Reported within Transportation and other services revenues and Net foreign currency gain/(loss) in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. 5 These components are included in the computation of net benefit costs and are reported within Other income/(expense) in the Consolidated Statements of Earnings. 6 Represents the historical noncontrolling interests and redeemable noncontrolling interests related to the Sponsored Vehicles reclassified to AOCI, upon the completion of the buy-in.

RISK MANAGEMENT AND FINANCIAL_2

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Summary of the Consolidated Statements of Financial Position location and carrying value of derivative instruments	The following table summarizes the maximum potential settlement amounts in the event of these specific circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position. December 31, 2019 Derivative Instruments Used as Cash Flow Hedges Derivative Instruments Used as Net Investment Hedges Non- Qualifying Derivative Instruments Total Gross Derivative Instruments as Presented Amounts Available for Offset Total Net Derivative Instruments (millions of Canadian dollars) Accounts receivable and other Foreign exchange contracts — — 161 161 (78 ) 83 Commodity contracts — — 163 163 (47 ) 116 Other contracts 1 — 3 4 — 4 1 — 327 328 1 (125 ) 203 Deferred amounts and other assets Foreign exchange contracts 10 — 71 81 (42 ) 39 Commodity contracts — — 17 17 (2 ) 15 Other contracts 2 — 1 3 — 3 12 — 89 101 (44 ) 57 Accounts payable and other Foreign exchange contracts (5 ) (13 ) (392 ) (410 ) 78 (332 ) Interest rate contracts (353 ) — — (353 ) — (353 ) Commodity contracts — — (173 ) (173 ) 47 (126 ) (358 ) (13 ) (565 ) (936 ) 2 125 (811 ) Other long-term liabilities Foreign exchange contracts — — (934 ) (934 ) 42 (892 ) Interest rate contracts (181 ) — — (181 ) — (181 ) Commodity contracts (5 ) — (60 ) (65 ) 2 (63 ) (186 ) — (994 ) (1,180 ) 44 (1,136 ) Total net derivative asset/(liability) Foreign exchange contracts 5 (13 ) (1,094 ) (1,102 ) — (1,102 ) Interest rate contracts (534 ) — — (534 ) — (534 ) Commodity contracts (5 ) — (53 ) (58 ) — (58 ) Other contracts 3 — 4 7 — 7 (531 ) (13 ) (1,143 ) (1,687 ) — (1,687 ) 1 Reported within Accounts receivable and other (2019 - $327 million ; 2018 - $498 million ) and Accounts receivable from affiliates (2019 - $1 million ; 2018 - nil ) on the Consolidated Statements of Financial Position. 2 Reported within Accounts payable and other (2019 - $920 million ; 2018 - $1,234 million ) and Accounts payable to affiliates (2019 - $16 million ; 2018 - nil ) on the Consolidated Statements of Financial Position. December 31, 2018 Derivative Derivative Non- Total Gross Amounts Total Net Derivative Instruments (millions of Canadian dollars) Accounts receivable and other Foreign exchange contracts — — 47 47 (37 ) 10 Interest rate contracts 22 — — 22 (2 ) 20 Commodity contracts 2 — 427 429 (114 ) 315 24 — 474 498 (153 ) 345 Deferred amounts and other assets Foreign exchange contracts 23 — 39 62 (39 ) 23 Interest rate contracts 5 — — 5 — 5 Commodity contracts 19 — 33 52 (21 ) 31 47 — 72 119 (60 ) 59 Accounts payable and other Foreign exchange contracts (5 ) — (610 ) (615 ) 37 (578 ) Interest rate contracts (163 ) — (178 ) (341 ) 2 (339 ) Commodity contracts — — (273 ) (273 ) 114 (159 ) Other contracts (1 ) — (4 ) (5 ) — (5 ) (169 ) — (1,065 ) (1,234 ) 153 (1,081 ) Other long-term liabilities Foreign exchange contracts (1 ) (15 ) (2,196 ) (2,212 ) 39 (2,173 ) Interest rate contracts (201 ) — — (201 ) — (201 ) Commodity contracts — — (178 ) (178 ) 21 (157 ) Other contracts (1 ) — (1 ) (2 ) — (2 ) (203 ) (15 ) (2,375 ) (2,593 ) 60 (2,533 ) Total net derivative asset/(liability) Foreign exchange contracts 17 (15 ) (2,720 ) (2,718 ) — (2,718 ) Interest rate contracts (337 ) — (178 ) (515 ) — (515 ) Commodity contracts 21 — 9 30 — 30 Other contracts (2 ) — (5 ) (7 ) — (7 ) (301 ) (15 ) (2,894 ) (3,210 ) — (3,210 )
Summary of the maturity and notional principal or quantity outstanding related to derivative instruments	The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments. 2019 2018 As at December 31, 2020 2021 2022 2023 2024 Thereafter Total Total Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars) 1,121 — — — — — 1,121 926 Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars) 5,631 4,946 5,182 1,804 1,856 — 19,419 19,075 Foreign exchange contracts - GBP forwards - sell (millions of GBP) 94 27 28 29 30 90 298 318 Foreign exchange contracts - Euro forwards - purchase (millions of Euro) — — — — — — — 226 Foreign exchange contracts - Euro forwards - sell (millions of Euro) 23 94 94 92 91 515 909 909 Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen) — — 72,500 — — — 72,500 52,662 Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars) 6,090 4,090 400 48 35 121 10,784 19,664 Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars) 3,533 1,569 — — — — 5,102 8,558 Equity contracts (millions of Canadian dollars) 20 34 — — — — 54 55 Commodity contracts - natural gas (billions of cubic feet) (33 ) 14 15 3 — — (1 ) (167 ) Commodity contracts - crude oil (millions of barrels) 28 — — — — — 28 4 Commodity contracts - NGL (millions of barrels) 2 — — — — — 2 — Commodity contracts - power (megawatt per hour (MW/H) 80 (3 ) (43 ) (43 ) (43 ) (43 ) 1 (16 ) 2 (7 ) 2 1 As at December 31, 2019 , thereafter includes an average net purchase/(sell) of power of (43) MW/H for 2025. 2 Total is an average net purchase/(sell) of power.
Schedule of effect of cash flow hedges and net investment hedges on consolidated earnings and consolidated comprehensive income, before income taxes	Year ended December 31, 2019 2018 (millions of Canadian dollars) Unrealized gain on derivative — 7 Unrealized gain on hedged item — 1 Realized loss on derivative — (8 ) Realized loss on hedged item — (1 ) The following table presents the effect of cash flow hedges and net investment hedges on our consolidated earnings and consolidated comprehensive income, before the effect of income taxes: 2019 2018 2017 (millions of Canadian dollars) Amount of unrealized gain/(loss) recognized in OCI Cash flow hedges Foreign exchange contracts (19 ) 19 (5 ) Interest rate contracts (559 ) (190 ) 6 Commodity contracts (25 ) 2 11 Other contracts 10 (3 ) 1 Net investment hedges Foreign exchange contracts 2 31 284 (591 ) (141 ) 297 Amount of (gain)/loss reclassified from AOCI to earnings Foreign exchange contracts 1 5 5 (104 ) Interest rate contracts 2,3 157 184 384 Commodity contracts 4 (1 ) (1 ) (9 ) Other contracts 5 (3 ) 3 8 158 191 279 1 Reported within Transportation and other services revenues and Net foreign currency gain/(loss) in the Consolidated Statements of Earnings. 2 Reported within Interest expense in the Consolidated Statements of Earnings. Effective January 1, 2019, hedge ineffectiveness will no longer be measured or recorded. See Note 2. 3 For the year ended December 31, 2017, includes settlements of $296 million loss related to the termination of long-term interest rate swaps as not highly probable to issue long-term debt. 4 Reported within Transportation and other services revenue, Commodity sales revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. 5 Reported within Operating and administrative expenses in the Consolidated Statements of Earnings.
Schedule of unrealized gains and losses associated with changes in the fair value of non-qualifying derivatives	The following table presents the unrealized gains and losses associated with changes in the fair value of our non-qualifying derivatives: Year ended December 31, 2019 2018 2017 (millions of Canadian dollars) Foreign exchange contracts 1 1,626 (1,390 ) 1,284 Interest rate contracts 2 178 5 157 Commodity contracts 3 (62 ) 485 (199 ) Other contracts 4 9 (3 ) — Total unrealized derivative fair value gain/(loss), net 1,751 (903 ) 1,242 1 For the respective annual periods, reported within Transportation and other services revenue ( 2019 - $930 million gain; 2018 - $1,108 million loss; 2017 - $800 million gain) and Net foreign currency gain/(loss) ( 2019 - $696 million gain; 2018 - $282 million loss; 2017 - $484 million gain) in the Consolidated Statements of Earnings. 2 Reported as a decrease within Interest expense in the Consolidated Statements of Earnings. 3 For the respective annual periods, reported within Transportation and other services revenue ( 2019 - $26 million loss; 2018 - $66 million gain; 2017 - $104 million loss), Commodity sales ( 2019 - $544 million loss; 2018 - $599 million gain; 2017 - $90 million gain), Commodity costs ( 2019 - $459 million gain; 2018 - $193 million loss; 2017 - $223 million loss) and Operating and administrative expense ( 2019 - $49 million gain; 2018 - $13 million gain; 2017 - $38 million gain) in the Consolidated Statements of Earnings. 4
Schedule of group credit concentrations and maximum credit exposure, with respect to derivative instruments	We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments: December 31, 2019 2018 (millions of Canadian dollars) Canadian financial institutions 146 28 United States financial institutions 40 107 European financial institutions 3 84 Asian financial institutions 92 6 Other 1 113 337 394 562 1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.
Schedule of derivative assets and liabilities measured at fair value	We have categorized our derivative assets and liabilities measured at fair value as follows: December 31, 2019 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 161 — 161 Commodity contracts — 33 130 163 Other contracts — 4 — 4 — 198 130 328 Long-term derivative assets Foreign exchange contracts — 81 — 81 Commodity contracts — 12 5 17 Other contracts — 3 — 3 — 96 5 101 Financial liabilities Current derivative liabilities Foreign exchange contracts — (410 ) — (410 ) Interest rate contracts — (353 ) — (353 ) Commodity contracts (5 ) (23 ) (145 ) (173 ) Other contracts — — — — (5 ) (786 ) (145 ) (936 ) Long-term derivative liabilities Foreign exchange contracts — (934 ) — (934 ) Interest rate contracts — (181 ) — (181 ) Commodity contracts — (6 ) (59 ) (65 ) Other contracts — — — — — (1,121 ) (59 ) (1,180 ) Total net financial asset/(liability) Foreign exchange contracts — (1,102 ) — (1,102 ) Interest rate contracts — (534 ) — (534 ) Commodity contracts (5 ) 16 (69 ) (58 ) Other contracts — 7 — 7 (5 ) (1,613 ) (69 ) (1,687 ) December 31, 2018 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 47 — 47 Interest rate contracts — 22 — 22 Commodity contracts 24 45 360 429 24 114 360 498 Long-term derivative assets Foreign exchange contracts — 62 — 62 Interest rate contracts — 5 — 5 Commodity contracts — 30 22 52 — 97 22 119 Financial liabilities Current derivative liabilities Foreign exchange contracts — (615 ) — (615 ) Interest rate contracts — (341 ) — (341 ) Commodity contracts (7 ) (28 ) (238 ) (273 ) Other contracts — (5 ) — (5 ) (7 ) (989 ) (238 ) (1,234 ) Long-term derivative liabilities Foreign exchange contracts — (2,212 ) — (2,212 ) Interest rate contracts — (201 ) — (201 ) Commodity contracts — (23 ) (155 ) (178 ) Other contracts — (2 ) — (2 ) — (2,438 ) (155 ) (2,593 ) Total net financial asset/(liability) Foreign exchange contracts — (2,718 ) — (2,718 ) Interest rate contracts — (515 ) — (515 ) Commodity contracts 17 24 (11 ) 30 Other contracts — (7 ) — (7 ) 17 (3,216 ) (11 ) (3,210 )
Schedule of significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments	The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows: December 31, 2019 Fair Value Unobservable Input Minimum Price/Volatility Maximum Price/Volatility Weighted Average Price/Volatility Unit of Measurement (fair value in millions of Canadian dollars) Commodity contracts - financial 1 Natural gas — Forward gas price 1.95 4.88 3.04 $/mmbtu 2 Crude 4 Forward crude price 44.24 82.29 52.76 $/barrel NGL 3 Forward NGL price 0.54 0.86 0.82 $/gallon Power (61 ) Forward power price 27.84 71.79 57.46 $/MW/H Commodity contracts - physical 1 Natural gas 28 Forward gas price 1.00 8.37 2.53 $/mmbtu 2 Crude (45 ) Forward crude price 40.20 90.75 70.27 $/barrel NGL 2 Forward NGL price 0.18 2.01 0.79 $/gallon (69 ) 1 Financial and physical forward commodity contracts are valued using a market approach valuation technique. 2 One million British thermal units (mmbtu).
Schedule of changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy	Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows: Year ended December 31, 2019 2018 (millions of Canadian dollars) Level 3 net derivative liability at beginning of period (11 ) (387 ) Total gain/(loss) Included in earnings 1 27 206 Included in OCI (25 ) 2 Settlements (60 ) 168 Level 3 net derivative liability at end of period (69 ) (11 ) 1 Reported within Transportation and other services revenue, Commodity costs and Operating and administrative expenses in the Consolidated Statements of Earnings.

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Schedule of income tax rate reconciliation	INCOME TAX RATE RECONCILIATION Year ended December 31, 2019 2018 2017 (millions of Canadian dollars) Earnings before income taxes 7,535 3,570 569 Canadian federal statutory income tax rate 15 % 15 % 15 % Expected federal taxes at statutory rate 1,130 536 85 Increase/(decrease) resulting from: Provincial and state income taxes 1 415 (24 ) 133 Foreign and other statutory rate differentials 129 94 (601 ) Impact of United States tax reform 2 — (2 ) (2,045 ) Effects of rate-regulated accounting 3 (63 ) (163 ) (189 ) Foreign allowable interest deductions 4 (29 ) (134 ) (124 ) Part VI.1 tax, net of federal Part I deduction 5 78 76 68 Impairment of goodwill — 192 15 United States BEAT tax 67 43 — Non-taxable portion of gain/(loss) on sale of investment to unrelated party 6 — 31 — Valuation allowance 7 26 (172 ) (17 ) Intercorporate investments 8 (14 ) (149 ) 77 Noncontrolling interests (13 ) (47 ) (80 ) Other (18 ) (44 ) (19 ) Income tax (recovery)/expense 1,708 237 (2,697 ) Effective income tax rate 22.7 % 6.6 % (474.0 )% 1 The change in provincial and state income taxes from 2018 to 2019 reflects the increase in earnings from operations and the impact of state tax rate changes in both the United States and Canada. 2 The amount was related to the enactment of the Tax Cuts and Jobs Act (TCJA) by the United States on December 22, 2017, which included a reduction in the federal corporate income tax rate from 35% to 21% effective for taxation years beginning after December 31, 2017. 3 The amount in 2019 included the federal component of the tax effect of the write-off of regulatory assets (Note 7) . 4 The decrease in foreign allowable interest deductions in 2019 was due to changes in the related loan portfolio and tax legislative changes in Canada, the United States, and Europe. 5 Part VI.1 tax is a tax levied on preferred share dividends paid in Canada. 6 The amount represents the federal component of the non-taxable portion of the gain on the sales of the Canadian Natural Gas Gathering and Processing Businesses in 2018. 7 The increase in 2018 is due to the federal component of the tax effect of a valuation allowance on the deferred tax assets related to an outside basis temporary difference that, in 2018, was more likely than not to be realized. 8 The amount relates to the federal component of changes in assertions regarding the manner of recovery of intercorporate investments such that deferred tax related to outside basis temporary differences was required to be recorded for MATL (Note 8), Renewable Assets in 2018 and for EIPLP in 2017.
Schedule of components of pretax earnings and income taxes	COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES Year ended December 31, 2019 2018 2017 (millions of Canadian dollars) Earnings/(loss) before income taxes Canada 3,560 118 2,200 United States 3,115 2,582 (2,431 ) Other 860 870 800 7,535 3,570 569 Current income taxes Canada 347 311 129 United States 107 66 46 Other 98 8 5 552 385 180 Deferred income taxes Canada 490 (598 ) 299 United States 672 439 (3,160 ) Other (6 ) 11 (16 ) 1,156 (148 ) (2,877 ) Income tax (recovery)/expense 1,708 237 (2,697 )
Schedule of major components of deferred income tax assets and liabilities	Major components of deferred income tax assets and liabilities are as follows: December 31, 2019 2018 (millions of Canadian dollars) Deferred income tax liabilities Property, plant and equipment (7,290 ) (7,018 ) Investments (4,620 ) (4,441 ) Regulatory assets (1,052 ) (756 ) Other (40 ) (192 ) Total deferred income tax liabilities (13,002 ) (12,407 ) Deferred income tax assets Financial instruments 679 1,103 Pension and OPEB plans 206 181 Loss carryforwards 1,693 1,820 Other 1,641 1,274 Total deferred income tax assets 4,219 4,378 Less valuation allowance (84 ) (51 ) Total deferred income tax assets, net 4,135 4,327 Net deferred income tax liabilities (8,867 ) (8,080 ) Presented as follows: Total deferred income tax assets 1,000 1,374 Total deferred income tax liabilities (9,867 ) (9,454 ) Net deferred income tax liabilities (8,867 ) (8,080 )
Schedule of unrecognized tax benefits	UNRECOGNIZED TAX BENEFITS Year ended December 31, 2019 2018 (millions of Canadian dollars) Unrecognized tax benefits at beginning of year 139 150 Gross increases for tax positions of current year 1 2 Gross decreases for tax positions of prior year (1 ) (12 ) Change in translation of foreign currency (4 ) 3 Lapses of statute of limitations (6 ) (3 ) Settlements — (1 ) Unrecognized tax benefits at end of year 129 139

PENSION AND OTHER POSTRETIREM_2

PENSION AND OTHER POSTRETIREMENT BENEFITS (Tables)	12 Months Ended
	Dec. 31, 2019
Retirement Benefits [Abstract]
Schedule of Changes in Projected Benefit Obligation, Plan Assets and Funded Status	For these plans, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets were as follows: Canada United States December 31, 2019 2018 2019 2018 (millions of Canadian dollars) Projected benefit obligation 1,481 1,422 103 1,214 Accumulated benefit obligation 1,361 1,299 98 1,179 Fair value of plan assets 1,087 1,064 — 1,045 The following table details the changes in the projected benefit obligation, the fair value of plan assets and the recorded assets or liabilities for our defined benefit pension plans: Canada United States December 31, 2019 2018 2019 2018 (millions of Canadian dollars) Change in projected benefit obligation Projected benefit obligation at beginning of year 3,997 4,033 1,214 1,279 Service cost 149 149 45 45 Interest cost 139 130 41 38 Participant contributions 32 25 — — Actuarial (gain)/loss 423 (146 ) 106 (103 ) Benefits paid (187 ) (184 ) (101 ) (60 ) Plan settlements 1 (99 ) — (1 ) (65 ) Transfers out (8 ) (10 ) (6 ) — Foreign currency exchange rate changes — — (63 ) 105 Other — — (5 ) (25 ) Projected benefit obligation at end of year 2 4,446 3,997 1,230 1,214 Change in plan assets Fair value of plan assets at beginning of year 3,523 3,619 1,045 1,097 Actual return/(loss) on plan assets 448 (42 ) 176 (48 ) Employer contributions 114 113 46 40 Participant contributions 32 25 — — Benefits paid (187 ) (184 ) (101 ) (60 ) Plan settlements 1 (99 ) — (1 ) (65 ) Transfers out (4 ) (8 ) — — Foreign currency exchange rate changes — — (56 ) 91 Other — — (5 ) (10 ) Fair value of plan assets at end of year 3 3,827 3,523 1,104 1,045 Underfunded status at end of year (619 ) (474 ) (126 ) (169 ) Presented as follows: Deferred amounts and other assets 35 29 — — Accounts payable and other (9 ) (9 ) (4 ) (4 ) Other long-term liabilities (645 ) (494 ) (122 ) (165 ) (619 ) (474 ) (126 ) (169 ) 1 Plan settlements for the Canadian Plans are related to the disposition of our federally regulated BC Field Services business. 2 The accumulated benefit obligation for our Canadian pension plans was $4.0 billion and $3.7 billion as at December 31, 2019 and 2018 , respectively. The accumulated benefit obligation for our United States pension plans was $1.2 billion as at December 31, 2019 and 2018 . 3 Assets in the amount of $ 10 million ( 2018 - $ 7 million ) and $ 51 million ( 2018 - $ 39 million ), related to our Canadian and United States non-registered supplemental pension plan obligations, are held in Grantor Trusts and Rabbi Trusts that, in accordance with federal tax regulations, are not restricted from creditors. These assets are committed for the future settlement of benefit obligations included in the underfunded status as at the end of the year, however they are excluded from plan assets for accounting purposes.
Schedule of Amount Recognized in Accumulated Other Comprehensive Income	The amount of pre-tax AOCI relating to our pension plans are as follows: Canada United States December 31, 2019 2018 2019 2018 (millions of Canadian dollars) Net actuarial loss 445 435 134 133 Prior service credit — — (2 ) (3 ) Total amount recognized in AOCI 1 445 435 132 130 1 Excludes amounts related to cumulative translation adjustment. The amount of pre-tax AOCI relating to our OPEB plans are as follows: Canada United States December 31, 2019 2018 2019 2018 (millions of Canadian dollars) Net actuarial gain (7 ) (29 ) (23 ) (15 ) Prior service credit (1 ) (2 ) (13 ) (15 ) Total amount recognized in AOCI 1 (8 ) (31 ) (36 ) (30 ) 1 Excludes amounts related to cumulative translation adjustment.
Schedule of Net Benefit Costs Recognized	The components of net periodic benefit cost and other amounts recognized in pre-tax Comprehensive income related to our OPEB plans are as follows: Canada United States Year ended December 31, 2019 2018 2017 2019 2018 2017 (millions of Canadian dollars) Service cost 5 8 7 2 3 5 Interest cost 10 10 10 10 10 10 Expected return on plan assets — — — (12 ) (12 ) (10 ) Amortization/settlement of net actuarial gain (7 ) — — — (1 ) — Amortization/curtailment of prior service (credit)/cost (1 ) — 1 (2 ) (4 ) — Net periodic benefit cost recognized in Earnings 7 18 18 (2 ) (4 ) 5 Amount recognized in OCI: Amortization/settlement of net actuarial gain/(loss) 7 — (1 ) — 1 1 Amortization/curtailment of prior service credit 1 — — 2 4 — Net actuarial (gain)/loss arising during the year 15 (46 ) (8 ) (8 ) (1 ) (42 ) Prior service (credit)/cost — — (3 ) — (8 ) 1 Total amount recognized in OCI 23 (46 ) (12 ) (6 ) (4 ) (40 ) Total amount recognized in Comprehensive income 30 (28 ) 6 (8 ) (8 ) (35 ) Canada United States Year ended December 31, 2019 2018 2017 2019 2018 2017 (millions of Canadian dollars) Service cost 149 149 156 45 45 48 Interest cost 139 130 116 41 38 35 Expected return on plan assets (245 ) (245 ) (201 ) (78 ) (88 ) (57 ) Amortization/settlement of net actuarial loss 41 25 29 2 7 10 Amortization/curtailment of prior service (credit)/cost — — — (1 ) 3 — Net periodic benefit cost 84 59 100 9 5 36 Defined contribution benefit cost 8 11 11 — — — Net pension cost recognized in Earnings 92 70 111 9 5 36 Amount recognized in OCI: Effect of plan combination — — — (6 ) — — Amortization/settlement of net actuarial loss (26 ) (11 ) (14 ) (2 ) (7 ) (9 ) Amortization/curtailment of prior service credit/(cost) — — — 1 (3 ) — Net actuarial loss arising during the year 115 112 38 8 28 — Total amount recognized in OCI 89 101 24 1 18 (9 ) Total amount recognized in Comprehensive income 181 171 135 10 23 27
Schedule of Actuarial Assumptions Used	The weighted average assumptions made in the measurement of the accumulated postretirement benefit obligation and net periodic benefit cost of our OPEB plans are as follows: Canada United States 2019 2018 2017 2019 2018 2017 Accumulated postretirement benefit obligation Discount rate 3.1 % 3.8 % 3.6 % 2.8 % 4.0 % 3.5 % Net periodic benefit cost Discount rate 3.8 % 3.6 % 4.0 % 4.0 % 3.3 % 4.0 % Rate of return on plan assets N/A N/A N/A 6.7 % 5.7 % 6.0 % The weighted average assumptions made in the measurement of the projected benefit obligation and net periodic benefit cost of our pension plans are as follows: Canada United States 2019 2018 2017 2019 2018 2017 Projected benefit obligation Discount rate 3.0 % 3.8 % 3.6 % 3.0 % 3.9 % 3.5 % Rate of salary increase 3.2 % 3.2 % 3.2 % 2.9 % 2.8 % 3.1 % Net periodic benefit cost Discount rate 3.8 % 3.6 % 4.0 % 3.9 % 3.4 % 4.0 % Expected rate of return on plan assets 7.0 % 6.8 % 6.5 % 8.0 % 7.4 % 7.2 % Rate of salary increase 3.2 % 3.2 % 3.7 % 2.9 % 2.9 % 3.3 %
Schedule of Other Postretirement Benefits	The following table details the changes in the accumulated postretirement benefit obligation, the fair value of plan assets and the recorded assets or liabilities for our defined benefit OPEB plans: Canada United States December 31, 2019 2018 2019 2018 (millions of Canadian dollars) Change in accumulated postretirement benefit obligation Accumulated postretirement benefit obligation at beginning of year 282 321 305 337 Service cost 5 8 2 3 Interest cost 10 10 10 10 Participant contributions — — 5 6 Actuarial (gain)/loss 15 (45 ) 7 (25 ) Benefits paid (6 ) (11 ) (28 ) (29 ) Plan amendments — — — (8 ) Foreign currency exchange rate changes — — (15 ) 27 Other (13 ) (1 ) 2 (16 ) Accumulated postretirement benefit obligation at end of year 293 282 288 305 Change in plan assets Fair value of plan assets at beginning of year — — 181 213 Actual return/(loss) on plan assets — — 27 (13 ) Employer contributions 6 11 10 8 Participant contributions — — 5 6 Benefits paid (6 ) (11 ) (28 ) (29 ) Foreign currency exchange rate changes — — (9 ) 16 Other — — 2 (20 ) Fair value of plan assets at end of year — — 188 181 Underfunded status at end of year (293 ) (282 ) (100 ) (124 ) Presented as follows: Deferred amounts and other assets — — — 2 Accounts payable and other (12 ) (12 ) (8 ) (7 ) Other long-term liabilities (281 ) (270 ) (92 ) (119 ) (293 ) (282 ) (100 ) (124 )
Schedule of Assumed Health Care Cost Trend Rates	The assumed rates for the next year used to measure the expected cost of benefits are as follows: Canada United States 2019 2018 2019 2018 Health care cost trend rate assumed for next year 4.0 % 5.6 % 7.2 % 7.4 % Rate to which the cost trend is assumed to decline (ultimate trend rate) 4.0 % 4.4 % 4.5 % 4.5 % Year that the rate reaches the ultimate trend rate N/A 2034 2037 2037
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates	A 1% change in the assumed health care cost trend rate would have the following effects for the year ended and as at December 31, 2019 : Canada United States 1% Increase 1% Decrease 1% Increase 1% Decrease (millions of Canadian dollars) Total service and interest costs 1 (1 ) 1 (1 ) Accumulated postretirement benefit obligation 21 (17 ) 19 (17 )
Schedule of Allocation of Plan Assets	The asset allocation targets and major categories of plan assets are as follows: Canada United States Target December 31, Target December 31, Asset Category Allocation 2019 2018 Allocation 2019 2018 Equity securities 43.4 % 46.4 % 45.8 % 45.0 % 55.2 % 52.7 % Fixed income securities 30.3 % 31.0 % 38.8 % 20.0 % 19.8 % 34.9 % Alternatives 1 26.3 % 22.6 % 15.4 % 35.0 % 25.0 % 12.4 % 1 Alternatives include investments in private debt, private equity, infrastructure and real estate funds.
Schedule of Changes in Fair Value of Plan Assets	Changes in the net fair value of OPEB plan assets classified as Level 3 in the fair value hierarchy were as follows: Canada United States December 31, 2019 2018 2019 2018 (millions of Canadian dollars) Balance at beginning of year — — 5 — Unrealized and realized gains — — 1 — Purchases and settlements, net — — 12 5 Balance at end of year — — 18 5 The following table summarizes the fair value of plan assets for our pension plans recorded at each fair value hierarchy level: Canada United States Level 1 1 Level 2 2 Level 3 3 Total Level 1 1 Level 2 2 Level 3 3 Total (millions of Canadian dollars) December 31, 2019 Cash and cash equivalents 184 — — 184 14 — — 14 Equity securities Canada 165 183 — 348 — — — — United States — — — — — 93 — 93 Global — 1,429 — 1,429 — 516 — 516 Fixed income securities Government 196 418 — 614 — 164 — 164 Corporate — 388 — 388 — 41 — 41 Alternatives 4 — — 852 852 — — 276 276 Forward currency contracts — 12 — 12 — — — — Total pension plan assets at fair value 545 2,430 852 3,827 14 814 276 1,104 December 31, 2018 Cash and cash equivalents 240 — — 240 56 — — 56 Equity securities Canada 138 481 — 619 — — — — United States — — — — — 110 — 110 Global — 992 — 992 — 440 — 440 Fixed income securities Government 218 453 — 671 — 265 — 265 Corporate — 457 — 457 — 44 — 44 Alternatives 4 — — 562 562 — — 130 130 Forward currency contracts — (18 ) — (18 ) — — — — Total pension plan assets at fair value 596 2,365 562 3,523 56 859 130 1,045 1 Level 1 assets include assets with quoted prices in active markets for identical assets. 2 Level 2 assets include assets with significant observable inputs. 3 Level 3 assets include assets with significant unobservable inputs. 4 Alternatives include investments in private debt, private equity, infrastructure and real estate funds. Changes in the net fair value of pension plan assets classified as Level 3 in the fair value hierarchy were as follows: Canada United States December 31, 2019 2018 2019 2018 (millions of Canadian dollars) Balance at beginning of year 562 340 130 56 Unrealized and realized gains 10 77 13 9 Purchases and settlements, net 280 145 133 65 Balance at end of year 852 562 276 130 OPEB Plans The following table summarizes the fair value of plan assets for our OPEB plans recorded at each fair value hierarchy level: Canada United States Level 1 1 Level 2 2 Level 3 3 Total Level 1 1 Level 2 2 Level 3 3 Total (millions of Canadian dollars) December 31, 2019 Cash and cash equivalents — — — — 2 — — 2 Equity securities United States — — — — — 75 — 75 Global — — — — — 38 — 38 Fixed income securities Government — — — — 40 15 — 55 Alternatives 4 — — — — — — 18 18 Total OPEB plan assets at fair value — — — — 42 128 18 188 December 31, 2018 Cash and cash equivalents — — — — 7 — — 7 Equity securities United States — — — — — 68 — 68 Global — — — — — 30 — 30 Fixed income securities Government — — — — 43 28 — 71 Corporate — — — — — — — — Alternatives 4 — — — — — — 5 5 Total OPEB plan assets at fair value — — — — 50 126 5 181 1 Level 1 assets include assets with quoted prices in active markets for identical assets. 2 Level 2 assets include assets with significant observable inputs. 3 Level 3 assets include assets with significant unobservable inputs. 4 Alternatives includes investments in private debt, private equity, infrastructure and real estate.
Schedule of Expected Benefit Payments and Employer Contributions	Year ending December 31, 2020 2021 2022 2023 2024 2025-2029 (millions of Canadian dollars) Pension Canada 180 186 192 198 204 1,105 United States 87 90 91 89 91 402 OPEB Canada 12 12 12 13 13 69 United States 23 22 21 20 19 82

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Assets and liabilities, lessee	Supplemental Statements of Financial Position Information December 31, 2019 January 1, 2019 (millions of Canadian dollars, except lease term and discount rate) Operating leases Operating lease right-of-use assets, net 1 713 771 Operating lease liabilities - current 2 94 86 Operating lease liabilities - long-term 3 689 770 Total operating lease liabilities 783 856 Weighted average remaining lease term Operating leases 13 years 14 years Weighted average discount rate Operating leases 4.3 % 4.3 % 1 Right-of-use assets are reported under Deferred amounts and other assets in the Consolidated Statements of Financial Position. 2 Current lease liabilities are reported under Accounts payable and other in the Consolidated Statements of Financial Position. 3 Long-term lease liabilities are reported under Other long-term liabilities in the Consolidated Statements of Financial Position.
Lessee, operating lease, liability, maturity	As at December 31, 2019 , our operating lease liabilities are expected to mature as follows: Operating leases (millions of Canadian dollars) 2020 128 2021 99 2022 94 2023 84 2024 79 Thereafter 588 Total undiscounted lease payments 1,072 Less imputed interest (289 ) Total operating lease liabilities 783
Operating lease, lease income	Year ended December 31, 2019 (millions of Canadian dollars) Operating lease income 265 Variable lease income 360 Total lease income 1 625 1 Lease income is recorded under Transportation and other services in the Consolidated Statements of Earnings.
Lessor, operating lease, payments to be received, maturity	As at December 31, 2019 , the following table sets out future lease payments to be received under operating lease contracts where we are the lessor: Operating leases (millions of Canadian dollars) 2020 236 2021 199 2022 188 2023 180 2024 178 Thereafter 2,276 Future lease payments 3,257

CHANGES IN OPERATING ASSETS A_2

CHANGES IN OPERATING ASSETS AND LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2019
CHANGES IN OPERATING ASSETS AND LIABILITIES
Schedule of changes in operating assets and liabilities	Year ended December 31, 2019 2018 2017 (millions of Canadian dollars) Accounts receivable and other (659 ) 857 (783 ) Accounts receivable from affiliates 6 54 24 Inventory (24 ) 164 (289 ) Deferred amounts and other assets 133 226 (138 ) Accounts payable and other 175 (151 ) 277 Accounts payable to affiliates (24 ) (122 ) (62 ) Interest payable (41 ) 25 124 Other long-term liabilities 175 (138 ) 509 (259 ) 915 (338 )

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Schedule of commitments	At December 31, 2019 , we have commitments as detailed below: Total Less than 1 year 2 years 3 years 4 years 5 years Thereafter (millions of Canadian dollars) Annual debt maturities 1 63,585 4,394 6,856 4,054 2,585 7,712 37,984 Interest obligations 2 29,498 2,416 2,296 2,216 2,076 1,915 18,579 Purchase of services, pipe and other materials, including transportation 3,4 9,448 2,891 1,507 1,217 564 570 2,699 Maintenance agreements 435 56 55 53 25 20 226 Land lease commitments 1,190 30 35 35 35 36 1,019 Total 104,156 9,787 10,749 7,575 5,285 10,253 60,507 1 Includes debentures, term notes, commercial paper and credit facility draws based on the facility's maturity date and excludes short-term borrowings, debt discount, debt issue costs and finance lease obligations. We have the ability under certain debt facilities to call and repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments could be materially different than presented above. 2 Includes debentures and term notes bearing interest at fixed, floating and fixed-to-floating rates. 3 Includes capital and operating commitments. 4 Consists primarily of gas transportation and storage contracts, firm capacity payments and gas purchase commitments, transportation, service and product purchase obligations, and power commitments.

CONDENSED CONSOLIDATING FINAN_2

CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2019
Condensed Financial Information Disclosure [Abstract]
Schedule of Long-term Debt Instruments	During the years ended December 31, 2019 and 2018 , we completed the following long-term debt issuances, excluding the debt exchange discussed below: Company Issue Date Principal Amount (millions of Canadian dollars unless otherwise stated) Enbridge Inc. October 2019 2.99% medium-term notes due October 2029 $1,000 November 2019 2.50% senior notes due July 2025 US$500 November 2019 3.13% senior notes due November 2029 US$1,000 November 2019 4.00% senior notes due November 2049 US$500 March 2018 Fixed-to-floating rate subordinated notes due March 2078 1 US$850 April 2018 Fixed-to-floating rate subordinated notes due April 2078 2 $750 April 2018 Fixed-to-floating rate subordinated notes due April 2078 3 US$600 Enbridge Gas Inc. August 2019 2.37% medium-term notes due August 2029 $400 August 2019 3.01% medium-term notes due August 2049 $300 Enbridge Pipelines Inc. February 2019 3.52% medium-term notes due February 2029 $600 February 2019 4.33% medium-term notes due February 2049 $600 Spectra Energy Partners, LP August 2019 3.24% senior notes due August 2029 4 US$500 January 2018 3.50% senior notes due January 2028 5 US$400 January 2018 4.15% senior notes due January 2048 5 US$400 1 Notes mature in 60 years and are callable on or after year 10 . For the initial 10 years , the notes carry a fixed interest rate of 6.25% . Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 364 basis points from years 10 to 30 , and a margin of 439 basis points from years 30 to 60 . 2 Notes mature in 60 years and are callable on or after year 10 . For the initial 10 years , the notes carry a fixed interest rate of 6.625% . Subsequently, the interest rate will be set to equal CDOR plus a margin of 432 basis points from years 10 to 30 , and a margin of 507 basis points from years 30 to 60 . 3 Notes mature in 60 years and are callable on or after year five . For the initial five years , the notes carry a fixed interest rate of 6.375% . Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 359 basis points from years five to 10 , a margin of 384 basis points from years 10 to 25 , and a margin of 459 basis points from years 25 to 60 . 4 Issued through Algonquin Gas Transmission, LLC, an operating subsidiary of SEP. 5 Issued through Texas Eastern, a wholly-owned operating subsidiary of SEP. Consenting SEP notes and EEP notes under Guarantee SEP Notes 1 EEP Notes 2 Floating Rate Senior Notes due 2020 4.200% Notes due 2021 4.600% Senior Notes due 2021 5.875% Notes due 2025 4.750% Senior Notes due 2024 5.950% Notes due 2033 3.500% Senior Notes due 2025 6.300% Notes due 2034 3.375% Senior Notes due 2026 7.500% Notes due 2038 5.950% Senior Notes due 2043 5.500% Notes due 2040 4.500% Senior Notes due 2045 7.375% Notes due 2045 1 As at December 31, 2019 , the aggregate outstanding principal amount of SEP notes was approximately US $3.9 billion . 2 As at December 31, 2019 , the aggregate outstanding principal amount of EEP notes was approximately US $3.0 billion . Enbridge Notes under Guarantees USD Denominated 1 CAD Denominated 2 Senior Floating Rate Notes due 2020 4.530% Senior Notes due 2020 Senior Floating Rate Notes due 2020 4.850% Senior Notes due 2020 2.900% Senior Notes due 2022 4.260% Senior Notes due 2021 4.000% Senior Notes due 2023 3.160% Senior Notes due 2021 3.500% Senior Notes due 2024 4.850% Senior Notes due 2022 2.500% Senior Notes due 2025 3.190% Senior Notes due 2022 4.250% Senior Notes due 2026 3.940% Senior Notes due 2023 3.700% Senior Notes due 2027 3.940% Senior Notes due 2023 3.125% Senior Notes due 2029 3.950% Senior Notes due 2024 4.500% Senior Notes due 2044 3.200% Senior Notes due 2027 5.500% Senior Notes due 2046 6.100% Senior Notes due 2028 4.000% Senior Notes due 2049 2.990% Senior Notes due 2029 7.220% Senior Notes due 2030 7.200% Senior Notes due 2032 5.570% Senior Notes due 2035 5.750% Senior Notes due 2039 5.120% Senior Notes due 2040 4.240% Senior Notes due 2042 4.570% Senior Notes due 2044 4.870% Senior Notes due 2044 4.560% Senior Notes due 2064 1 As at December 31, 2019 , the aggregate outstanding principal amount of the Enbridge United States dollar denominated notes was approximately US $7.9 billion . 2 As at December 31, 2019 , the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was approximately $7.6 billion .
Condensed Consolidating Statements of Earnings and Comprehensive Income	Condensed Consolidating Statements of Earnings and Comprehensive Income for the year ended December 31, 2019 Parent Issuer and Guarantor Subsidiary Issuer and Guarantor - SEP Subsidiary Issuer and Guarantor - EEP Subsidiary Non-Guarantors Consolidating and elimination adjustments Consolidated - Enbridge (millions of Canadian dollars) Operating revenues Commodity sales — — — 29,309 — 29,309 Gas distribution sales — — — 4,205 — 4,205 Transportation and other services — — — 16,555 — 16,555 Total operating revenues — — — 50,069 — 50,069 Operating Expenses Commodity costs — — — 28,802 — 28,802 Gas distribution costs — — — 2,202 — 2,202 Operating and administrative 128 5 (16 ) 6,874 — 6,991 Depreciation and amortization 67 — — 3,324 — 3,391 Impairment of long-lived assets — — — 423 — 423 Impairment of goodwill — — — — — — Total operating expenses 195 5 (16 ) 41,625 — 41,809 Operating income/(loss) (195 ) (5 ) 16 8,444 — 8,260 Income from equity investments 70 133 — 1,366 (66 ) 1,503 Equity earnings from consolidated subsidiaries 3,881 1,189 1,043 1,696 (7,809 ) — Other — — — — — — Net foreign currency gain/(loss) 1,671 — — (106 ) (1,088 ) 477 Gain/(loss) on dispositions (7 ) — — (293 ) — (300 ) Other, including other income from affiliates 1,944 2 189 573 (2,450 ) 258 Interest expense (1,268 ) (330 ) (591 ) (2,966 ) 2,492 (2,663 ) Earnings before income taxes 6,096 989 657 8,714 (8,921 ) 7,535 Income tax (expense)/recovery (391 ) 44 6 (1,985 ) 618 (1,708 ) Earnings 5,705 1,033 663 6,729 (8,303 ) 5,827 Earnings attributable to noncontrolling interests and redeemable noncontrolling interests — — — — (122 ) (122 ) Earnings attributable to controlling interests 5,705 1,033 663 6,729 (8,425 ) 5,705 Preference share dividends (383 ) — — — — (383 ) Earnings attributable to common shareholders 5,322 1,033 663 6,729 (8,425 ) 5,322 Earnings 5,705 1,033 663 6,729 (8,303 ) 5,827 Total other comprehensive income/(loss) (2,992 ) (67 ) 51 (929 ) 830 (3,107 ) Comprehensive income 2,713 966 714 5,800 (7,473 ) 2,720 Comprehensive income attributable to noncontrolling interests — — — — (7 ) (7 ) Comprehensive income attributable to controlling interests 2,713 966 714 5,800 (7,480 ) 2,713 Condensed Consolidating Statements of Earnings and Comprehensive Income for the year ended December 31, 2018 Parent Issuer and Guarantor Subsidiary Issuer and Guarantor - SEP Subsidiary Issuer and Guarantor - EEP Subsidiary Non-Guarantors Consolidating and elimination adjustments Consolidated - Enbridge (millions of Canadian dollars) Operating revenues Commodity sales — — — 27,660 — 27,660 Gas distribution sales — — — 4,360 — 4,360 Transportation and other services — — — 14,358 — 14,358 Total operating revenues — — — 46,378 — 46,378 Operating Expenses Commodity costs — — — 26,818 — 26,818 Gas distribution costs — — — 2,583 — 2,583 Operating and administrative 180 14 54 6,622 (78 ) 6,792 Depreciation and amortization 59 — — 3,187 — 3,246 Impairment of long-lived assets — — — 1,104 — 1,104 Impairment of goodwill — — — 1,019 — 1,019 Total operating expenses 239 14 54 41,333 (78 ) 41,562 Operating income/(loss) (239 ) (14 ) (54 ) 5,045 78 4,816 Income from equity investments 302 142 — 1,360 (295 ) 1,509 Equity earnings/(loss) from consolidated subsidiaries 3,119 (1,634 ) 921 (1,581 ) (825 ) — Other Net foreign currency gain/(loss) (829 ) 8 — 80 219 (522 ) Gain/(loss) on dispositions 360 — — (406 ) — (46 ) Other, including other income/(expense) from affiliates 945 72 153 254 (908 ) 516 Interest expense (1,080 ) (302 ) (557 ) (1,689 ) 925 (2,703 ) Earnings/(loss) before income taxes 2,578 (1,728 ) 463 3,063 (806 ) 3,570 Income tax recovery/(expense) 304 (319 ) 3 (4,373 ) 4,148 (237 ) Earnings/(loss) 2,882 (2,047 ) 466 (1,310 ) 3,342 3,333 Earnings attributable to noncontrolling interests and redeemable noncontrolling interests — — — — (451 ) (451 ) Earnings/(loss) attributable to controlling interests 2,882 (2,047 ) 466 (1,310 ) 2,891 2,882 Preference share dividends (367 ) — — — — (367 ) Earnings/(loss) attributable to common shareholders 2,515 (2,047 ) 466 (1,310 ) 2,891 2,515 Earnings/(loss) 2,882 (2,047 ) 466 (1,310 ) 3,342 3,333 Total other comprehensive income/(loss) 3,788 (9 ) 28 556 (225 ) 4,138 Comprehensive income/(loss) 6,670 (2,056 ) 494 (754 ) 3,117 7,471 Comprehensive income attributable to noncontrolling interests — — — — (801 ) (801 ) Comprehensive income/(loss) attributable to controlling interests 6,670 (2,056 ) 494 (754 ) 2,316 6,670 Condensed Consolidating Statements of Earnings and Comprehensive Income for the year ended December 31, 2017 Parent Issuer and Guarantor Subsidiary Issuer and Guarantor - SEP Subsidiary Issuer and Guarantor - EEP Subsidiary Non-Guarantors Consolidating and elimination adjustments Consolidated - Enbridge (millions of Canadian dollars) Operating revenues Commodity sales — — — 26,286 — 26,286 Gas distribution sales — — — 4,215 — 4,215 Transportation and other services — — — 13,877 — 13,877 Total operating revenues — — — 44,378 — 44,378 Operating expenses Commodity costs — — — 26,065 — 26,065 Gas distribution costs — — — 2,572 — 2,572 Operating and administrative 169 146 16 6,111 — 6,442 Depreciation and amortization 56 — — 3,107 — 3,163 Impairment of long lived assets — — — 4,463 — 4,463 Impairment of goodwill — — — 102 — 102 Total operating expenses 225 146 16 42,420 — 42,807 Operating income/(loss) (225 ) (146 ) (16 ) 1,958 — 1,571 Income from equity investments 471 118 — 981 (468 ) 1,102 Equity earnings from consolidated subsidiaries 2,130 752 926 881 (4,689 ) — Other Net foreign currency gain/(loss) 500 — — (22 ) (241 ) 237 Gain/(loss) on dispositions (11 ) — — 27 — 16 Other, including other income/(expense) from affiliates 871 11 139 74 (896 ) 199 Interest expense (816 ) (221 ) (691 ) (1,753 ) 925 (2,556 ) Earnings before income taxes 2,920 514 358 2,146 (5,369 ) 569 Income tax (expense)/recovery (61 ) — 9 2,706 43 2,697 Earnings 2,859 514 367 4,852 (5,326 ) 3,266 Earnings attributable to noncontrolling interests and redeemable noncontrolling interests — — — — (407 ) (407 ) Earnings attributable to controlling interests 2,859 514 367 4,852 (5,733 ) 2,859 Preference share dividends (330 ) — — — — (330 ) Earnings attributable to common shareholders 2,529 514 367 4,852 (5,733 ) 2,529 Earnings 2,859 514 367 4,852 (5,326 ) 3,266 Total other comprehensive income/(loss) (2,031 ) 12 204 (412 ) (51 ) (2,278 ) Comprehensive income 828 526 571 4,440 (5,377 ) 988 Comprehensive income attributable to noncontrolling interests — — — — (160 ) (160 ) Comprehensive income attributable to controlling interests 828 526 571 4,440 (5,537 ) 828
Condensed Consolidating Statements of Financial Position	Condensed Consolidating Statements of Financial Position as at December 31, 2019 Parent Issuer and Guarantor Subsidiary Issuer and Guarantor - SEP Subsidiary Issuer and Guarantor - EEP Subsidiary Non-Guarantors Consolidating and elimination adjustments Consolidated - Enbridge (millions of Canadian dollars) Assets Current assets Cash and cash equivalents — 33 4 611 — 648 Restricted cash 9 — — 19 — 28 Accounts receivable and other 429 8 4 6,340 — 6,781 Accounts receivable from affiliates 746 — 12 (164 ) (525 ) 69 Short-term loans receivable from affiliates 1,691 — 3,961 4,417 (10,069 ) — Inventory — — — 1,299 — 1,299 2,875 41 3,981 12,522 (10,594 ) 8,825 Property, plant and equipment, net 248 — — 93,475 — 93,723 Long-term loans receivable from affiliates 47,285 73 2,387 35,672 (85,417 ) — Investments in subsidiaries 80,456 18,956 5,180 14,782 (119,374 ) — Long-term investments 1,701 932 — 14,467 (572 ) 16,528 Restricted long-term investments — — — 434 — 434 Deferred amounts and other assets 998 1 1 7,282 (849 ) 7,433 Intangible assets, net 247 — — 1,926 — 2,173 Goodwill — — — 33,153 — 33,153 Deferred income taxes 486 — — 514 — 1,000 Total assets 134,296 20,003 11,549 214,227 (216,806 ) 163,269 Liabilities and equity Current liabilities Short-term borrowings — — — 898 — 898 Accounts payable and other 2,765 28 1 7,745 (476 ) 10,063 Accounts payable to affiliates 736 367 83 (640 ) (525 ) 21 Interest payable 279 52 51 242 — 624 Short-term loans payable to affiliates 367 2,058 1,991 5,653 (10,069 ) — Current portion of long-term debt 2,160 518 — 1,726 — 4,404 6,307 3,023 2,126 15,624 (11,070 ) 16,010 Long-term debt 27,290 4,435 3,789 24,147 — 59,661 Other long-term liabilities 1,295 2 12 7,864 (849 ) 8,324 Long-term loans payable to affiliates 33,686 — 3,112 48,619 (85,417 ) — Deferred income taxes — 271 — 13,887 (4,291 ) 9,867 68,578 7,731 9,039 110,141 (101,627 ) 93,862 Equity Controlling interests 1 65,718 12,272 2,510 104,086 (118,543 ) 66,043 Noncontrolling interests — — — — 3,364 3,364 65,718 12,272 2,510 104,086 (115,179 ) 69,407 Total liabilities and equity 134,296 20,003 11,549 214,227 (216,806 ) 163,269 1 Equity attributable to controlling interests for parent issuer and guarantor excludes reciprocal shareholding balance included within consolidating and elimination adjustments. Condensed Consolidating Statements of Financial Position as at December 31, 2018 Parent Issuer and Guarantor Subsidiary Issuer and Guarantor - SEP Subsidiary Issuer and Guarantor - EEP Subsidiary Non-Guarantors Consolidating and elimination adjustments Consolidated - Enbridge (millions of Canadian dollars) Assets Current assets Cash and cash equivalents — 16 — 502 — 518 Restricted cash 9 — — 110 — 119 Accounts receivable and other 283 15 8 6,211 — 6,517 Accounts receivable from affiliates 726 — 13 (142 ) (518 ) 79 Short-term loans receivable from affiliates 3,943 — 3,689 653 (8,285 ) — Inventory — — — 1,339 — 1,339 4,961 31 3,710 8,673 (8,803 ) 8,572 Property, plant and equipment, net 140 — — 94,400 — 94,540 Long-term loans receivable from affiliates 10,318 73 2,539 1,344 (14,274 ) — Investments in subsidiaries 78,474 19,777 6,363 15,567 (120,181 ) — Long-term investments 4,561 987 — 14,841 (3,682 ) 16,707 Restricted long-term investments — — — 323 — 323 Deferred amounts and other assets 1,700 9 17 8,558 (1,726 ) 8,558 Intangible assets, net 234 — — 2,138 — 2,372 Goodwill — — — 34,459 — 34,459 Deferred income taxes 817 — — 229 328 1,374 Total assets 101,205 20,877 12,629 180,532 (148,338 ) 166,905 Liabilities and equity Current liabilities Short-term borrowings — — — 1,024 — 1,024 Accounts payable and other 2,742 7 34 7,059 (6 ) 9,836 Accounts payable to affiliates 946 233 56 (677 ) (518 ) 40 Interest payable 283 56 105 225 — 669 Short-term loans payable to affiliates 426 682 — 7,177 (8,285 ) — Environmental liabilities, current — — — 27 — 27 Current portion of long-term debt 1,853 — 683 723 — 3,259 6,250 978 878 15,558 (8,809 ) 14,855 Long-term debt 22,893 7,276 6,943 23,215 — 60,327 Other long-term liabilities 2,428 2 30 8,100 (1,726 ) 8,834 Long-term loans payable to affiliates 76 — 1,502 12,696 (14,274 ) — Deferred income taxes — 331 — 13,523 (4,400 ) 9,454 31,647 8,587 9,353 73,092 (29,209 ) 93,470 Equity Controlling interests 1 69,558 12,290 3,276 107,440 (123,094 ) 69,470 Noncontrolling interests — — — — 3,965 3,965 69,558 12,290 3,276 107,440 (119,129 ) 73,435 Total liabilities and equity 101,205 20,877 12,629 180,532 (148,338 ) 166,905 1 Equity attributable to controlling interests for parent issuer and guarantor excludes reciprocal shareholding balance included within consolidating and elimination adjustments.
Condensed Consolidating Statements of Cash Flows	Condensed Consolidating Statements of Cash Flows for the year ended December 31, 2019 Parent Issuer and Guarantor Subsidiary Issuer and Guarantor - SEP Subsidiary Issuer and Guarantor - EEP Subsidiary Non-Guarantors Consolidating and elimination adjustments Consolidated - Enbridge (millions of Canadian dollars) Net cash provided by operating activities 2,246 1,676 (365 ) 9,675 (3,834 ) 9,398 Investing activities Capital expenditures (75 ) — — (5,417 ) — (5,492 ) Long-term investments and restricted long-term investments (26 ) (11 ) — (1,122 ) — (1,159 ) Distributions from equity investments in excess of cumulative earnings — 24 1,196 393 (1,196 ) 417 Additions to intangible assets (68 ) — — (132 ) — (200 ) Affiliate loans, net — — — (314 ) — (314 ) Proceeds from disposition — — — 2,110 — 2,110 Contributions to subsidiaries (4,759 ) — (12 ) — 4,771 — Return of share capital from subsidiary companies 5,281 — — — (5,281 ) — Advances to affiliates (50,897 ) — (2,778 ) (60,787 ) 114,462 — Repayment of advances to affiliates 15,808 — 2,357 22,136 (40,301 ) — Other — — — (20 ) — (20 ) Net cash (used in)/provided by investing activities (34,736 ) 13 763 (43,153 ) 72,455 (4,658 ) Financing activities Net change in short-term borrowings — — — (127 ) — (127 ) Net change in commercial paper and credit facility draws 3,158 (2,011 ) (1,017 ) 695 — 825 Debenture and term note issues, net of issue costs 3,621 — — 2,555 — 6,176 Debenture and term note repayments (1,450 ) — (2,514 ) (704 ) — (4,668 ) Contributions from noncontrolling interests — — — — 12 12 Distributions to noncontrolling interests — — — — (254 ) (254 ) Contributions from redeemable noncontrolling interests — — — — — — Distributions to redeemable noncontrolling interests — — — — — — Contributions from parents — — — 4,771 (4,771 ) — Distributions to parents — (1,014 ) (651 ) (8,888 ) 10,553 — Redemption of preferred shares — — — (300 ) — (300 ) Common shares issued 18 — — — — 18 Preference share dividends (383 ) — — — — (383 ) Common share dividends (5,973 ) — — — — (5,973 ) Advances from affiliates 46,860 5,678 8,249 53,675 (114,462 ) — Repayment of advances from affiliates (13,361 ) (4,321 ) (4,454 ) (18,165 ) 40,301 — Other — (4 ) (7 ) (60 ) — (71 ) Net cash provided by/(used in) financing activities 32,490 (1,672 ) (394 ) 33,452 (68,621 ) (4,745 ) Effect of translation of foreign denominated cash and cash equivalents and restricted cash — — — 44 — 44 Net increase/(decrease) in cash and cash equivalents and restricted cash — 17 4 18 — 39 Cash and cash equivalents and restricted cash at beginning of year 9 16 — 612 — 637 Cash and cash equivalents and restricted cash at end of year 9 33 4 630 — 676 Condensed Consolidating Statements of Cash Flows for the year ended December 31, 2018 Parent Issuer and Guarantor Subsidiary Issuer and Guarantor - SEP Subsidiary Issuer and Guarantor - EEP Subsidiary Non-Guarantors Consolidating and elimination adjustments Consolidated - Enbridge (millions of Canadian dollars) Net cash provided by/(used in) operating activities 1,696 1,751 (239 ) 11,683 (4,389 ) 10,502 Investing activities Capital expenditures (28 ) — — (6,778 ) — (6,806 ) Long-term investments and restricted long-term investments (81 ) (12 ) — (1,297 ) 78 (1,312 ) Distributions from equity investments in excess of cumulative earnings 287 45 982 1,232 (1,269 ) 1,277 Additions to intangible assets (43 ) — — (497 ) — (540 ) Proceeds from dispositions 1,790 — — 2,662 — 4,452 Contributions to subsidiaries (8,131 ) (79 ) (13 ) (1,655 ) 9,878 — Return of share capital from subsidiaries 3,753 — — — (3,753 ) — Advances to affiliates (6,863 ) — (1,703 ) (5,685 ) 14,251 — Repayment of advances to affiliates 9,427 518 1,504 4,124 (15,573 ) — Affiliate loans, net (76 ) (76 ) Other — — — (12 ) — (12 ) Net cash provided by/(used in) investing activities 111 472 770 (7,982 ) 3,612 (3,017 ) Financing activities Net change in short-term borrowings — — — (420 ) — (420 ) Net change in commercial paper and credit facility draws (734 ) (962 ) (1,009 ) 449 — (2,256 ) Debenture and term note issues, net of issue costs 2,554 — — 983 — 3,537 Debenture and term note repayments — (648 ) (509 ) (3,288 ) — (4,445 ) Sale of noncontrolling interests in subsidiaries — — — — 1,289 1,289 Contributions from noncontrolling interests — — — — 24 24 Distributions to noncontrolling interests — — — — (857 ) (857 ) Contributions from redeemable noncontrolling interests — — — — 70 70 Distributions to redeemable noncontrolling interests — — — — (325 ) (325 ) Contributions from parents — — 1,007 8,223 (9,230 ) — Distributions to parents — (1,902 ) (666 ) (6,564 ) 9,132 — Sponsored Vehicle buy-in cash payment (64 ) — — — — (64 ) Redemption of preferred shares — — — (210 ) — (210 ) Common shares issued 21 648 — — (648 ) 21 Preference share dividends (364 ) — — — — (364 ) Common share dividends (3,480 ) — — — — (3,480 ) Advances from affiliates 710 1,474 3,501 8,566 (14,251 ) — Repayment of advances from affiliates (443 ) (826 ) (2,855 ) (11,449 ) 15,573 — Other — (5 ) — (18 ) — (23 ) Net cash (used in)/provided by financing activities (1,800 ) (2,221 ) (531 ) (3,728 ) 777 (7,503 ) Effect of translation of foreign denominated cash and cash equivalents and restricted cash — — — 68 — 68 Net increase in cash and cash equivalents and restricted cash 7 2 — 41 — 50 Cash and cash equivalents and restricted cash at beginning of year 2 14 — 571 — 587 Cash and cash equivalents and restricted cash at end of year 9 16 — 612 — 637 Condensed Consolidating Statements of Cash Flows for the year ended December 31, 2017 Parent Issuer and Guarantor Subsidiary Issuer and Guarantor - SEP Subsidiary Issuer and Guarantor - EEP Subsidiary Non-Guarantors Consolidating and elimination adjustments Consolidated - Enbridge (millions of Canadian dollars) Net cash (used in)/provided by operating activities 620 355 (695 ) 9,654 (3,276 ) 6,658 Investing activities Capital expenditures (21 ) — — (8,266 ) — (8,287 ) Long-term investments and restricted long-term investments (202 ) (51 ) — (3,535 ) 202 (3,586 ) Distributions from equity investments in excess of cumulative earnings 36 22 921 103 (957 ) 125 Additions to intangible assets (47 ) — — (742 ) — (789 ) Cash acquired in Merger Transaction — — — 682 — 682 Proceeds from dispositions — — 1,742 1,103 (2,217 ) 628 Contributions to subsidiaries (4,866 ) — (2,056 ) — 6,922 — Return of share capital from subsidiaries 2,192 — 1,532 — (3,724 ) — Advances to affiliates (7,145 ) (519 ) (1,410 ) (3,020 ) 12,094 — Repayment of advances to affiliates 4,506 — 2,129 2,887 (9,522 ) — Affiliate loans, net — — — (22 ) — (22 ) Other — — — 212 — 212 Net cash (used in)/provided by investing activities (5,547 ) (548 ) 2,858 (10,598 ) 2,798 (11,037 ) Financing activities Net change in short-term borrowings — — — 721 — 721 Net change in commercial paper and credit facility draws (1,845 ) 1,965 (316 ) (1,053 ) — (1,249 ) Debenture and term note issues, net of issue costs 8,177 519 — 787 — 9,483 Debenture and term note repayments (1,711 ) (533 ) — (2,810 ) — (5,054 ) Purchase of interest in consolidated subsidiary — — (475 ) (1,969 ) 2,217 (227 ) Contributions from noncontrolling interests — — — — 832 832 Distributions to noncontrolling interests — — — — (919 ) (919 ) Contributions from redeemable noncontrolling interests 563 — — — 615 1,178 Distributions to redeemable noncontrolling interests — — — — (247 ) (247 ) Contributions from parents — — — 6,922 (6,922 ) — Distributions to parents — (1,987 ) (789 ) (6,093 ) 8,869 — Preference shares issued 489 — — — — 489 Redemption of preferred shares — — (1,613 ) 1,613 — — Common shares issued 1,549 227 1,646 — (1,873 ) 1,549 Preference share dividends (330 ) — (478 ) — 478 (330 ) Common share dividends 1 (2,336 ) — — (414 ) — (2,750 ) Advances from affiliates 407 — 2,613 9,074 (12,094 ) — Repayment of advances from affiliates (40 ) — (2,847 ) (6,635 ) 9,522 — Net cash provided by/(used in) financing activities 4,923 191 (2,259 ) 143 478 3,476 Effect of translation of foreign denominated cash and cash equivalents and restricted cash — — (2 ) (70 ) — (72 ) Net decrease in cash and cash equivalents and restricted cash (4 ) (2 ) (98 ) (871 ) — (975 ) Cash and cash equivalents and restricted cash at beginning of year 6 16 98 1,442 — 1,562 Cash and cash equivalents and restricted cash at end of year 2 14 — 571 — 587 1 Common share dividends for the year ended December 31, 2017 includes amounts distributed by Spectra Energy Corp. related to dividends accrued prior to the Merger Transaction.

QUARTERLY FINANCIAL DATA (UNA_2

QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information	Q1 Q2 Q3 Q4 Total (unaudited; millions of Canadian dollars, except per share amounts) 2019 Operating revenues 12,856 13,263 11,598 12,352 50,069 Operating income 2,619 2,285 1,588 1,768 8,260 Earnings 2,023 1,830 1,060 914 5,827 Earnings attributable to controlling interests 1,986 1,832 1,045 842 5,705 Earnings attributable to common shareholders 1,891 1,736 949 746 5,322 Earnings per common share Basic 0.94 0.86 0.47 0.37 2.64 Diluted 0.94 0.86 0.47 0.36 2.63 2018 Operating revenues 12,726 10,745 11,345 11,562 46,378 Operating income 878 1,571 854 1,513 4,816 Earnings 510 1,327 213 1,283 3,333 Earnings attributable to controlling interests 534 1,160 4 1,184 2,882 Earnings/(loss) attributable to common shareholders 445 1,071 (90 ) 1,089 2,515 Earnings/(loss) per common share Basic 0.26 0.63 (0.05 ) 0.60 1.46 Diluted 0.26 0.63 (0.05 ) 0.60 1.46

BUSINESS OVERVIEW (Details)

BUSINESS OVERVIEW (Details) $ in Millions	Feb. 27, 2017CAD ($)shares	Dec. 31, 2019operating_segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of operating segments | operating_segment		5
Spectra Energy Corp
Business Acquisition [Line Items]
Purchase price | $	$ 37,509
Shares paid to acquiree for each share of acquiree stock (in shares) | shares	0.984
Ownership interest acquired (as a percent)	100.00%

SIGNIFICANT ACCOUNTING POLICI_3

SIGNIFICANT ACCOUNTING POLICIES - REGULATION (Details)	Dec. 31, 2019CAD ($)
Deferral for Depreciation for Phase-In Plans under U.S. GAAP Guidance
REGULATION
Regulatory assets	$ 0

SIGNIFICANT ACCOUNTING POLICI_4

SIGNIFICANT ACCOUNTING POLICIES - REVENUE RECOGNITION (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Revenue recognized	$ 185	$ 183
Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue recognized	$ 169	$ 208	$ 196

SIGNIFICANT ACCOUNTING POLICI_5

SIGNIFICANT ACCOUNTING POLICIES - PROPERTY, PLANT AND EQUIPMENT (Details)	12 Months Ended
	Dec. 31, 2019number_of_primary_method_of_depreciation
Accounting Policies [Abstract]
Number of primary methods of depreciation which are utilized	2

SIGNIFICANT ACCOUNTING POLICI_6

SIGNIFICANT ACCOUNTING POLICIES - STOCK-BASED COMPENSATION (Details)	12 Months Ended
	Dec. 31, 2019
Performance Stock Units (PSUs)
STOCK-BASED COMPENSATION
Vesting period	3 years
Restricted Stock Units (RSU)
STOCK-BASED COMPENSATION
Vesting period	35 months

CHANGES IN ACCOUNTING POLICIES

CHANGES IN ACCOUNTING POLICIES (Details) - CAD ($) $ in Millions	Jan. 01, 2019	Dec. 31, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease right-of-use assets	$ 771	$ 713
Operating lease liabilities	856	$ 783
Pre-existing liabilities related to impaired lease	$ 85
Weighted average discount rate (percent)	4.32%	4.30%
ASU 2016-02 (Topic 842)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease right-of-use assets	$ 771
Operating lease liabilities	$ 771

REVENUE (Details)

REVENUE (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									$ 19,697	$ 20,797
Total operating revenues	$ 12,352	$ 11,598	$ 13,263	$ 12,856	$ 11,562	$ 11,345	$ 10,745	$ 12,726	50,069	46,378	$ 44,378
Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									69	1,658
Transferred over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									19,628	19,139
Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									14,302	13,291
Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									578	519
Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									423	815
Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									4,210	4,376
Total operating revenues									4,205	4,360	4,215
Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									180	206
Commodity sales
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									4	1,590
Revenue not from contract with customers									29,305	26,070
Total operating revenues									29,309	27,660	26,286
Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									1,067	(489)
Liquids Pipelines
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									9,191	8,589
Liquids Pipelines | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Liquids Pipelines | Transferred over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									9,191	8,589
Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									5,172	6,555
Gas Transmission and Midstream | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									4	1,590
Gas Transmission and Midstream | Transferred over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									5,168	4,965
Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									5,154	5,447
Gas Distribution and Storage | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									65	68
Gas Distribution and Storage | Transferred over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									5,089	5,379
Renewable Power Generation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									180	206
Renewable Power Generation | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Renewable Power Generation | Transferred over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									180	206
Energy Services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Energy Services | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Energy Services | Transferred over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Business segments | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									9,191	8,589
Total operating revenues									10,219	8,079	8,913
Business segments | Liquids Pipelines | Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									9,082	8,488
Business segments | Liquids Pipelines | Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									109	101
Business segments | Liquids Pipelines | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Business segments | Liquids Pipelines | Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Business segments | Liquids Pipelines | Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Business segments | Liquids Pipelines | Commodity sales
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Revenue not from contract with customers									0	0
Business segments | Liquids Pipelines | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									659	(894)
Business segments | Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									5,172	6,555
Total operating revenues									5,207	6,571
Business segments | Gas Transmission and Midstream | Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									4,477	3,928
Business segments | Gas Transmission and Midstream | Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									268	222
Business segments | Gas Transmission and Midstream | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									423	815
Business segments | Gas Transmission and Midstream | Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Business segments | Gas Transmission and Midstream | Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Business segments | Gas Transmission and Midstream | Commodity sales
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									4	1,590
Revenue not from contract with customers									0	0
Business segments | Gas Transmission and Midstream | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									30	6
Business segments | Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									5,154	5,447
Total operating revenues									5,179	5,470	4,992
Business segments | Gas Distribution and Storage | Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									743	875
Business segments | Gas Distribution and Storage | Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									201	196
Business segments | Gas Distribution and Storage | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Business segments | Gas Distribution and Storage | Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									4,210	4,376
Business segments | Gas Distribution and Storage | Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Business segments | Gas Distribution and Storage | Commodity sales
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Revenue not from contract with customers									0	0
Business segments | Gas Distribution and Storage | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									9	9
Business segments | Renewable Power Generation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									180	206
Total operating revenues									567	567	534
Business segments | Renewable Power Generation | Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Business segments | Renewable Power Generation | Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Business segments | Renewable Power Generation | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Business segments | Renewable Power Generation | Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Business segments | Renewable Power Generation | Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									180	206
Business segments | Renewable Power Generation | Commodity sales
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Revenue not from contract with customers									0	0
Business segments | Renewable Power Generation | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									387	361
Business segments | Energy Services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Total operating revenues									29,374	26,228
Business segments | Energy Services | Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Business segments | Energy Services | Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Business segments | Energy Services | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Business segments | Energy Services | Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Business segments | Energy Services | Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Business segments | Energy Services | Commodity sales
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Revenue not from contract with customers									29,305	26,070
Business segments | Energy Services | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									(2)	4
Eliminations and Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Total operating revenues									(477)	(537)
Eliminations and Other | Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Eliminations and Other | Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Eliminations and Other | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Eliminations and Other | Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Eliminations and Other | Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Eliminations and Other | Commodity sales
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Revenue not from contract with customers									0	0
Eliminations and Other | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									(16)	25
Intersegment revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									(461)	(562)
Total operating revenues									(477)	(537)	(410)
Intersegment revenue | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									369	384
Intersegment revenue | Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									5	10
Intersegment revenue | Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									16	14
Intersegment revenue | Renewable Power Generation
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									0	0
Intersegment revenue | Energy Services
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									71	154
Eliminations and Other
Disaggregation of Revenue [Line Items]
Total operating revenues									0	0	0
Eliminations and Other | Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total operating revenues									0	0	0
Eliminations and Other | Commodity sales
Disaggregation of Revenue [Line Items]
Total operating revenues									$ 0	$ 0	$ 0

REVENUE - Contract Balances (De

REVENUE - Contract Balances (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Accounts receivable, net	$ 2,099	$ 1,929
Contract with customer, asset	216	191
Contract with customer, liability	$ 1,424	$ 1,297

REVENUE - Narrative (Details)

REVENUE - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue recognized	$ 185	$ 183
Increase (decrease) in contract with customers, liability	358	$ 449
Remaining performance obligation	65,800
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue from Contract with Customer [Abstract]
Remaining performance obligation	$ 7,100
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation, period	1 year

SEGMENTED INFORMATION (Details)

SEGMENTED INFORMATION (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segmented Information
Total operating revenues	$ 12,352	$ 11,598	$ 13,263	$ 12,856	$ 11,562	$ 11,345	$ 10,745	$ 12,726	$ 50,069	$ 46,378	$ 44,378
Commodity and gas distribution costs									(31,004)	(29,401)	(28,637)
Operating and administrative									(6,991)	(6,792)	(6,442)
Impairment of long-lived assets									(423)	(1,104)	(4,463)
Impairment of goodwill									0	(1,019)	(102)
Income/(loss) from equity investments									1,503	1,509	1,102
Other income/(expense)									435	(52)	452
Earnings/(loss) before interest, income tax expense, and depreciation and amortization									13,589	9,519	6,288
Depreciation and amortization									(3,391)	(3,246)	(3,163)
Interest expense									(2,663)	(2,703)	(2,556)
Income tax (expense) recovery									(1,708)	(237)	2,697
Earnings									5,827	3,333	3,266
Capital expenditures									5,550	6,872	8,422
Property, plant and equipment, net	93,723				94,540				93,723	94,540
Liquids Pipelines
Segmented Information
Impairment of goodwill										0
Gas Distribution and Storage
Segmented Information
Impairment of goodwill										0
Renewable Power Generation
Segmented Information
Impairment of goodwill										0
Business segments | Liquids Pipelines
Segmented Information
Total operating revenues									10,219	8,079	8,913
Commodity and gas distribution costs									(29)	(16)	(18)
Operating and administrative									(3,298)	(3,124)	(2,949)
Impairment of long-lived assets									(21)	(180)	0
Impairment of goodwill										0	0
Income/(loss) from equity investments									780	577	416
Other income/(expense)									30	(5)	33
Earnings/(loss) before interest, income tax expense, and depreciation and amortization									7,681	5,331	6,395
Capital expenditures									2,548	3,102	2,799
Property, plant and equipment, net	48,783				49,214				48,783	49,214
Business segments | Gas Transmission and Midstream
Segmented Information
Total operating revenues									5,207	6,571	7,067
Commodity and gas distribution costs									0	(1,481)	(2,834)
Operating and administrative									(2,232)	(2,102)	(1,756)
Impairment of long-lived assets									(105)	(914)	(4,463)
Impairment of goodwill										(1,019)	(102)
Income/(loss) from equity investments									682	930	653
Other income/(expense)									(181)	349	166
Earnings/(loss) before interest, income tax expense, and depreciation and amortization									3,371	2,334	(1,269)
Capital expenditures									1,753	2,644	4,016
Property, plant and equipment, net	25,268				25,601				25,268	25,601
Business segments | Gas Distribution and Storage
Segmented Information
Total operating revenues									5,179	5,470	4,992
Commodity and gas distribution costs									(2,354)	(2,748)	(2,689)
Operating and administrative									(1,149)	(1,111)	(960)
Impairment of long-lived assets									0	0	0
Impairment of goodwill										0	0
Income/(loss) from equity investments									4	11	23
Other income/(expense)									67	89	24
Earnings/(loss) before interest, income tax expense, and depreciation and amortization									1,747	1,711	1,390
Capital expenditures									1,100	1,066	1,177
Property, plant and equipment, net	15,622				15,148				15,622	15,148
Business segments | Renewable Power Generation
Segmented Information
Total operating revenues									567	567	534
Commodity and gas distribution costs									(2)	(7)	0
Operating and administrative									(189)	(157)	(163)
Impairment of long-lived assets									(297)	(4)	0
Impairment of goodwill										0	0
Income/(loss) from equity investments									31	(28)	6
Other income/(expense)									1	(2)	(5)
Earnings/(loss) before interest, income tax expense, and depreciation and amortization									111	369	372
Capital expenditures									23	33	321
Property, plant and equipment, net	3,658				4,335				3,658	4,335
Business segments | Energy Services
Segmented Information
Total operating revenues									29,374	26,228	23,282
Commodity and gas distribution costs									(29,091)	(25,689)	(23,508)
Operating and administrative									(44)	(73)	(47)
Impairment of long-lived assets									0	0	0
Impairment of goodwill										0	0
Income/(loss) from equity investments									8	18	8
Other income/(expense)									3	(2)	2
Earnings/(loss) before interest, income tax expense, and depreciation and amortization									250	482	(263)
Capital expenditures									2	0	1
Property, plant and equipment, net	24				22				24	22
Intersegment revenue
Segmented Information
Total operating revenues									(477)	(537)	(410)
Commodity and gas distribution costs									472	540	412
Operating and administrative									(79)	(225)	(567)
Impairment of long-lived assets									0	(6)	0
Impairment of goodwill										0	0
Income/(loss) from equity investments									(2)	1	(4)
Other income/(expense)									515	(481)	232
Earnings/(loss) before interest, income tax expense, and depreciation and amortization									429	(708)	(337)
Capital expenditures									124	27	$ 108
Property, plant and equipment, net	$ 368				$ 220				$ 368	$ 220
Customer Concentration Risk | Sales Revenue, Net | Largest Non-Affiliated Customer
Out of period adjustments
Concentration (percent)											11.80%

SEGMENTED INFORMATION - GEOGRAP

SEGMENTED INFORMATION - GEOGRAPHIC INFORMATION (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Geographic Information
Total operating revenues	$ 12,352	$ 11,598	$ 13,263	$ 12,856	$ 11,562	$ 11,345	$ 10,745	$ 12,726	$ 50,069	$ 46,378	$ 44,378
Property, plant and equipment, net	93,723				94,540				93,723	94,540
Canada
Geographic Information
Total operating revenues									19,954	19,023	18,076
Property, plant and equipment, net	45,993				44,716				45,993	44,716
United States
Geographic Information
Total operating revenues									30,115	27,355	$ 26,302
Property, plant and equipment, net	$ 47,730				$ 49,824				$ 47,730	$ 49,824

EARNINGS PER COMMON SHARE (Deta

EARNINGS PER COMMON SHARE (Details) - $ / shares shares in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings Per Share [Abstract]
Weighted average basic shares outstanding, pro forma (in shares)	6	12	13
Weighted average shares outstanding (in shares)	2,017	1,724	1,525
Effect of dilutive options (in shares)	3	3	7
Diluted weighted average shares outstanding (in shares)	2,020	1,727	1,532
Anti-dilutive stock options excluded from diluted earnings per common share calculation (in shares)	17.8	26.8	14.3
Weighted average exercise price of anti-dilutive stock options (in CAD per share)	$ 53.56	$ 50.38	$ 56.71

REGULATORY MATTERS - Liquids Pi

REGULATORY MATTERS - Liquids Pipelines (Narrative) (Details)	12 Months Ended
	Dec. 31, 2019
Canadian Mainline
Public Utilities, General Disclosures [Line Items]
Term of CTS establishing a Canadian Local Toll	10 years
Southern Lights Pipeline
Public Utilities, General Disclosures [Line Items]
Pre-determined after-tax rate of return on equity (ROE) (as a percent)	10.00%

REGULATORY MATTERS - Gas Transm

REGULATORY MATTERS - Gas Transmission and Midstream (Narrative) (Details) - Deferred income taxes - Gas Transmission and Midstream - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Public Utilities, General Disclosures [Line Items]
Regulatory assets	$ 511	$ 826
BC FIeld Services
Public Utilities, General Disclosures [Line Items]
Regulatory assets	$ 349

REGULATORY MATTERS - Enbridge G

REGULATORY MATTERS - Enbridge Gas Distribution Inc. (Narrative) (Details) - Enbridge Gas Distribution	12 Months Ended
	Dec. 31, 2019
Public Utilities, General Disclosures [Line Items]
Term of incentive regulation framework	5 years
Inflation stretch factor (percent)	0.30%

REGULATORY MATTERS - Schedule o

REGULATORY MATTERS - Schedule of Regulatory Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Liquids Pipelines | Tolling deferrals
Regulatory Liabilities [Line Items]
Regulatory (liabilities)	$ (25)	$ (28)
Liquids Pipelines | Pipeline future abandonment costs
Regulatory Liabilities [Line Items]
Regulatory (liabilities)	(293)	(201)
Liquids Pipelines | Deferred income taxes
Regulatory Assets [Line Items]
Regulatory assets	1,767	1,673
Liquids Pipelines | Recoverable income taxes
Regulatory Assets [Line Items]
Regulatory assets	24	27
Liquids Pipelines | Other
Regulatory Assets [Line Items]
Regulatory assets	32	0
Gas Transmission and Midstream | Pipeline future abandonment costs
Regulatory Liabilities [Line Items]
Regulatory (liabilities)	(159)	(111)
Gas Transmission and Midstream | Regulatory liability related to income taxes3
Regulatory Liabilities [Line Items]
Regulatory (liabilities)	(866)	(912)
Gas Transmission and Midstream | Deferred income taxes
Regulatory Assets [Line Items]
Regulatory assets	511	826
Gas Transmission and Midstream | Long-term debt
Regulatory Assets [Line Items]
Regulatory assets	108	124
Gas Transmission and Midstream | Other
Regulatory Assets [Line Items]
Regulatory assets	215	205
Gas Distribution and Storage
Regulatory Assets [Line Items]
Regulatory assets	145	0
Gas Distribution and Storage | Purchased gas variance
Regulatory Liabilities [Line Items]
Regulatory (liabilities)	(19)
Gas Distribution and Storage | Future removal and site restoration reserves5
Regulatory Liabilities [Line Items]
Regulatory (liabilities)	(1,424)	(1,107)
Gas Distribution and Storage | Other
Regulatory Liabilities [Line Items]
Regulatory (liabilities)		(4)
Gas Distribution and Storage | Deferred income taxes
Regulatory Assets [Line Items]
Regulatory assets	1,273	1,132
Gas Distribution and Storage | Long-term debt
Regulatory Assets [Line Items]
Regulatory assets	362	387
Gas Distribution and Storage | Purchased gas variance
Regulatory Assets [Line Items]
Regulatory assets		197
Gas Distribution and Storage | Pension plans and OPEB
Regulatory Assets [Line Items]
Regulatory assets	275	118
Gas Distribution and Storage | Constant dollar net salvage adjustment
Regulatory Assets [Line Items]
Regulatory assets	0	$ 6
Gas Distribution and Storage | Other
Regulatory Assets [Line Items]
Regulatory assets	$ 88

ACQUISITIONS AND DISPOSITIONS -

ACQUISITIONS AND DISPOSITIONS - Acquisitions (Narrative) (Details) $ in Millions	Feb. 27, 2017CAD ($)shares	Dec. 31, 2017CAD ($)	Dec. 31, 2019CAD ($)reporting_unit	Dec. 31, 2017CAD ($)	Dec. 31, 2018CAD ($)	Feb. 27, 2017$ / shares
Business Acquisition [Line Items]
Goodwill			$ 33,153		$ 34,459
Spectra Energy Capital, LLC
Business Acquisition [Line Items]
Goodwill	$ 36,656	$ 36,700		$ 36,700
Purchase price	$ 37,509
Shares paid to acquiree for each share of acquiree stock (in shares) | shares	0.984
Ownership interest acquired (as a percent)	100.00%
Cash paid in lieu of fractional shares	$ 3
Acquisition-related expenses/transaction costs incurred	$ 231
Costs incurred				$ 180
Revenues generated by acquiree		5,740
Earnings generated by acquiree		$ 2,574
Common Shares | Spectra Energy Capital, LLC
Business Acquisition [Line Items]
Shares paid as consideration (in shares) | shares	691,000,000
Share price (in USD per share) | $ / shares						$ 41.34
Value of shares issued	$ 37,429
Share options | Spectra Energy Capital, LLC
Business Acquisition [Line Items]
Shares paid as consideration (in shares) | shares	3,500,000
Value of shares issued	$ 77
Gas Transmission and Midstream
Business Acquisition [Line Items]
Goodwill			$ 19,844		$ 20,777
Number of reporting units | reporting_unit			2

ACQUISITIONS AND DISPOSITIONS_2

ACQUISITIONS AND DISPOSITIONS - Summary of Estimated Fair Values Assigned to Net Assets (Details) shares in Millions, $ in Millions	Feb. 27, 2017CAD ($)shares	Dec. 31, 2017CAD ($)	Sep. 30, 2017CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Feb. 24, 2017$ / shares
Fair value of net assets acquired:
Goodwill				$ 33,153	$ 34,459
Purchase price:
Fair value adjustment to long-term debt related to rate-regulated entities				844	964
Decrease to deferred amounts and other assets				$ 133	$ 226	$ (138)
Spectra Energy Capital, LLC
Fair value of net assets acquired:
Current assets	$ 2,432
Property, plant and equipment, net	33,555
Restricted long-term investments	144
Long-term investments	5,000
Deferred amounts and other assets	2,390
Intangible assets, net	1,288
Current liabilities	(3,982)
Long-term debt	(21,444)
Other long-term liabilities	(1,983)
Deferred income taxes	(7,670)
Noncontrolling interests	(8,877)
Fair value of net assets acquired	853
Goodwill	36,656	$ 36,700				$ 36,700
Fair value of net assets acquired and goodwill	37,509
Purchase price:
Cash	3
Purchase price	37,509
Net carrying value of accounts receivable	1,174
Gross amount due	1,190
Not expected to be collected	16
Business Combination, adjustment, current assets		67
Business Combination, adjustment, current liabilities		548
Business Combination, adjustment, long-term debt		481
Reclassification from intangible assets to property, plant and equipment	830
Increase in the book value of debt	1,500
Fair value adjustment to long-term debt related to rate-regulated entities	629
Spectra Energy Capital, LLC | Common Shares
Purchase price:
Equity issued	37,429
Spectra Energy Capital, LLC | Earned stock compensation awards
Purchase price:
Equity issued	$ 77
Spectra Energy Capital, LLC | Spectra Energy Partners, LP
Purchase price:
SEP common units outstanding to the public (in shares) | shares	78.4
Closing price per common unit (in USD per share) | $ / shares							$ 44.88
Spectra Energy Capital, LLC | Various equity investments of acquiree
Purchase price:
Long-term investments (as a percent)	50.00%
Spectra Energy Capital, LLC | PennEast
Purchase price:
Long-term investments (as a percent)	20.00%
Sabal Trail
Purchase price:
Increase to noncontrolling interests			$ 85
BC Pipelines & Field Services
Purchase price:
Decrease to property, plant and equipment		1,955
Decrease to deferred income tax liabilities		661
Decrease to deferred amounts and other assets		530
Increase to noncontrolling interests		$ 1,824

ACQUISITIONS AND DISPOSITIONS_3

ACQUISITIONS AND DISPOSITIONS - Schedule of Fair Value of Intangible Assets Acquired (Details) - Spectra Energy Capital, LLC $ in Millions	Feb. 27, 2017CAD ($)
Acquired Finite-Lived Intangible Assets [Line Items]
Fair Value	$ 1,288
Customer relationships
Acquired Finite-Lived Intangible Assets [Line Items]
Weighted average amortization rate (percent)	3.70%
Fair Value	$ 739
Project agreement
Acquired Finite-Lived Intangible Assets [Line Items]
Weighted average amortization rate (percent)	4.00%
Fair Value	$ 105
Software
Acquired Finite-Lived Intangible Assets [Line Items]
Weighted average amortization rate (percent)	11.10%
Fair Value	$ 329
Other
Acquired Finite-Lived Intangible Assets [Line Items]
Weighted average amortization rate (percent)	4.20%
Fair Value	$ 115

ACQUISITIONS AND DISPOSITIONS_4

ACQUISITIONS AND DISPOSITIONS - Schedule of Supplemental Pro Forma Consolidated Financial Information (Details) - Spectra Energy Capital, LLC $ in Millions	12 Months Ended
	Dec. 31, 2017CAD ($)
Business Acquisition [Line Items]
Revenues	$ 45,669
Earnings attributable to common shareholders	2,902
Merger transaction costs	180
After-tax merger transaction costs	$ 131

ACQUISITIONS AND DISPOSITIONS_5

ACQUISITIONS AND DISPOSITIONS - Assets Held for Sale (Narrative) (Details) - Disposal group, held-for-sale, not discontinued operations - CAD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Montana-Alberta Tie Line (MATL)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment of long-lived assets to be disposed of	$ 297
Asset Impairment | Line 10 Crude Oil
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued operation, provision for loss (gain) on disposal, before income tax		$ 154

ACQUISITIONS AND DISPOSITIONS_6

ACQUISITIONS AND DISPOSITIONS - Schedule of Net Assets Held for Sale (Details) - Disposal group, held-for-sale, not discontinued operations - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Accounts receivable and other (current assets held for sale)	$ 28	$ 117
Deferred amounts and other assets (long-term assets held for sale)	269	2,383
Accounts payable and other (current liabilities held for sale)	0	(63)
Other long-term liabilities (long-term liabilities held for sale)	0	(96)
Net assets held for sale	297	2,341
Disposal group, property, plant and equipment, noncurrent	$ 181	$ 2,100

ACQUISITIONS AND DISPOSITIONS_7

ACQUISITIONS AND DISPOSITIONS - Dispositions (Narrative) (Details) € in Millions, $ in Millions, $ in Millions	Dec. 31, 2019CAD ($)	Nov. 01, 2019USD ($)	Nov. 01, 2019CAD ($)	Oct. 01, 2019USD ($)	Oct. 01, 2019CAD ($)	Oct. 01, 2018CAD ($)	Aug. 01, 2018USD ($)	Aug. 01, 2018CAD ($)	Jul. 04, 2018CAD ($)	Jul. 31, 2017USD ($)	Jul. 31, 2017CAD ($)	Mar. 01, 2017USD ($)	Mar. 01, 2017CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2018EUR (€)	Dec. 31, 2017USD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Aug. 01, 2018CAD ($)	Jul. 31, 2018	Jun. 30, 2018CAD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Goodwill																					$ 33,153	$ 34,459
Deferred income tax (recovery)/expense														$ 1,156		$ (148)			$ (2,877)
Impairment loss														423		1,104			4,463
Impairment of goodwill														0		1,019			102
Gain on disposal of assets														(254)		(8)			120
Liquids Pipelines
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Goodwill																					7,951	8,324
Impairment of goodwill																0
Dispositions | St. Lawrence Gas
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash proceeds from sale of interest		$ 55	$ 72
Gain (loss) on disposal of interest			$ (10)
Dispositions | Enbridge Gas New Brunswick
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash proceeds from sale of interest				$ 331
Gain (loss) on disposal of interest					$ (3)
Goodwill included in assets subsequently disposed					$ 133
Dispositions | Canadian Natural Gas Gathering and Processing Business
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal group, consideration									$ 4,300
Impairment of goodwill									$ 1,019
Dispositions | Canadian Renewable Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposal of interest																62
Dispositions | United States Renewable Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposal of interest															$ 13	17
Dispositions | Liquids Pipelines | Sandpiper
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash proceeds from sale of assets															30	38		$ 111	148
Gain on disposal of assets															22	29		$ 63	$ 83
Dispositions | Liquids Pipelines | Olympic Pipeline
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash proceeds from sale of interest										$ 160	$ 203
Dispositions | Liquids Pipelines | Ozark Pipeline
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash proceeds from sale of assets												$ 220	$ 294
Gain on disposal of assets												$ 10	$ 14
Disposal group, held-for-sale, not discontinued operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Other long-term liabilities (long-term liabilities held for sale)																					0	96
Disposal group, held-for-sale, not discontinued operations | Texas Express Ngl System
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Goodwill																									$ 262
Equity investment																									$ 447
Other income/(expense) | Dispositions | Hohe See Offshore Wind Project
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposal of interest																(20)	€ (14)
Other income/(expense) | Dispositions | Liquids Pipelines | Olympic Pipeline
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposal of interest										$ 21	$ 27
Canadian Renewable Assets | Dispositions
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Noncontrolling interest, ownership percentage by parent																		49.00%	49.00%					49.00%
United States Renewable Assets | Dispositions
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Noncontrolling interest, ownership percentage by parent																								49.00%
Federally Regulated Facilities
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Goodwill included in assets subsequently disposed																					$ 55
Cash proceeds from sale of assets	$ 1,700
Gain on disposal of assets														$ (268)
Provincially Regulated Facilities
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash proceeds from sale of assets						$ 2,500
Gain on disposal of assets																34
Hohe See Offshore Wind Project | Dispositions
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest of equity method investment (as a percent)							49.00%																49.00%	49.00%
The Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of equity method investments								$ 1,750
Deferred income tax (recovery)/expense																(196)
The Assets | Renewable energy assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Noncontrolling interest, ownership percentage by parent																				51.00%	51.00%
Renewable energy assets | The Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Deferred income tax (recovery)/expense																(267)
Enbridge (U.S.) Inc. | Dispositions | Midcoast Operating L.P.
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposal of interest							$ (32)	$ (41)
Disposal group, consideration							1,100																$ 1,400
Impairment loss																$ 913			$ 4,400
Other long-term liabilities (long-term liabilities held for sale)							$ 298								$ 274					$ 230	$ 299	$ 375	$ 387
Impairment of goodwill																			$ 102

ACCOUNTS RECEIVABLE AND OTHER_2

ACCOUNTS RECEIVABLE AND OTHER (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Receivables [Abstract]
Trade receivables and unbilled revenues	$ 5,164	$ 4,711
Short-term portion of derivative assets	327	498
Other	1,290	1,308
Accounts receivable and other	6,781	6,517
Allowance for doubtful accounts receivable	$ 50	$ 64

INVENTORY (Details)

INVENTORY (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Inventory Disclosure [Abstract]
Natural gas	$ 696	$ 776
Crude oil	542	482
Other commodities	61	81
Total	1,299	1,339
Inventory adjustments	$ 188	$ 327	$ 58

PROPERTY, PLANT AND EQUIPMENT -

PROPERTY, PLANT AND EQUIPMENT - Schedule of Property, Plant and Equipment (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	$ 113,963	$ 112,404
Total accumulated depreciation	(20,240)	(17,864)
Property, plant and equipment, net	$ 93,723	94,540
Pipelines
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	2.50%
Total property, plant and equipment	$ 56,330	51,647
Facilities and equipment
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	2.70%
Total property, plant and equipment	$ 29,287	27,149
Land and right-of-way
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	2.00%
Total property, plant and equipment	$ 2,947	2,614
Gas mains, services and other
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	2.70%
Total property, plant and equipment	$ 12,194	12,088
Storage
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	2.30%
Total property, plant and equipment	$ 2,748	2,730
Wind turbines, solar panels and other
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	4.10%
Total property, plant and equipment	$ 4,914	5,015
Other
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	6.40%
Total property, plant and equipment	$ 1,486	1,463
Under construction
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	0.00%
Total property, plant and equipment	$ 4,057	$ 9,698

PROPERTY, PLANT AND EQUIPMENT_2

PROPERTY, PLANT AND EQUIPMENT - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Depreciation expense	$ 3,000	$ 2,900	$ 2,900
Impairment loss	423	$ 1,104	$ 4,463
Access Northeast Project
Property, Plant and Equipment [Line Items]
Impairment loss	$ 105

VARIABLE INTEREST ENTITIES - CO

VARIABLE INTEREST ENTITIES - CONSOLIDATED VARIABLE INTEREST ENTITIES (Narrative) (Details)	12 Months Ended
	Dec. 31, 2019
Enbridge Canadian Renewable LP (ECRLP)
Schedule of Equity Method Investments [Line Items]
Direct common interest (as a percent)	51.00%
DakTex
Schedule of Equity Method Investments [Line Items]
Ownership interest in subsidiary (as a percent)	75.00%
DakTex | EEP
Schedule of Equity Method Investments [Line Items]
Ownership interest in subsidiary (as a percent)	25.00%
Bakken Pipeline System
Schedule of Equity Method Investments [Line Items]
Ownership interest of equity method investment (as a percent)	27.60%
Other Limited Partnerships
Schedule of Equity Method Investments [Line Items]
Direct common interest (as a percent)	100.00%

VARIABLE INTEREST ENTITIES - Sc

VARIABLE INTEREST ENTITIES - Schedule of Assets and Liabilities of Consolidated VIEs (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Assets
Cash and cash equivalents	$ 648	$ 518
Restricted cash	28	119
Accounts receivable and other	6,781	6,517
Accounts receivable from affiliates	69	79
Inventory	1,299	1,339
Total Current assets	8,825	8,572
Property, plant and equipment, net	93,723	94,540
Long-term investments	16,528	16,707
Restricted long-term investments	434	323
Deferred amounts and other assets	7,433	8,558
Intangible assets, net	2,173	2,372
Goodwill	33,153	34,459
Total assets	163,269	166,905
Liabilities
Short-term borrowings	898	1,024
Accounts payable and other	10,063	9,863
Accounts payable to affiliates	21	40
Interest payable	624	669
Environmental liabilities		27
Current portion of long-term debt	4,404	3,259
Total Current liabilities	16,010	14,855
Long-term debt	59,661	60,327
Other long-term liabilities	8,324	8,834
Deferred income taxes	8,867	8,080
Total Liabilities	93,862	93,470
Variable Interest Entity, Primary Beneficiary
Assets
Cash and cash equivalents	208	506
Restricted cash	1	61
Accounts receivable and other	76	2,006
Accounts receivable from affiliates	0	38
Inventory	4	244
Total Current assets	289	2,855
Property, plant and equipment, net	3,392	72,349
Long-term investments	15	6,481
Restricted long-term investments	69	244
Deferred amounts and other assets	4	3,156
Intangible assets, net	124	705
Goodwill	0	29
Deferred income taxes	0	131
Total assets	3,893	85,950
Liabilities
Short-term borrowings	0	275
Accounts payable and other	56	2,925
Accounts payable to affiliates	0	4
Interest payable	0	303
Environmental liabilities	0	22
Current portion of long-term debt	0	1,034
Total Current liabilities	56	4,563
Long-term debt	0	29,577
Other long-term liabilities	130	5,074
Deferred income taxes	5	6,911
Total Liabilities	191	46,125
Net assets before noncontrolling interests	$ 3,702	$ 39,825

VARIABLE INTEREST ENTITIES - UN

VARIABLE INTEREST ENTITIES - UNCONSOLIDATED VARIABLE INTEREST ENTITIES (Narrative) (Details) - Variable Interest Entity, Not Primary Beneficiary	1 Months Ended
	Dec. 31, 2018
Variable Interest Entity [Line Items]
Direct common interest (as a percent)	22.80%
Gray Oak Holdings LLC
Variable Interest Entity [Line Items]
Direct common interest (as a percent)	35.00%

VARIABLE INTEREST ENTITIES - _2

VARIABLE INTEREST ENTITIES - Schedule of the Carrying Amount of Interest in VIEs (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Variable Interest Entity, Not Primary Beneficiary
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	$ 1,896	$ 3,947
Maximum Exposure to Loss	6,148	8,949
Aux Sable Liquid Products L.P.
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	267	311
Maximum Exposure to Loss	331	375
Eolien Maritime France SAS
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	67	68
Maximum Exposure to Loss	725	784
Affiliate loan receivable	166	202
Enbridge Renewable Infrastructure Investments S.a.r.l. (ERII)
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	141	127
Maximum Exposure to Loss	2,720	3,037
Affiliate loan receivable	766	461
Gray Oak Holdings LLC
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	463
Maximum Exposure to Loss	935
Illinois Extension Pipeline Company, L.L.C.
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE		724
Maximum Exposure to Loss		724
Nexus Gas Transmission, LLC
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE		1,757
Maximum Exposure to Loss		2,668
PennEast Pipeline Company, LLC
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	106	97
Maximum Exposure to Loss	368	385
Rampion Offshore Wind Limited
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	600	638
Maximum Exposure to Loss	620	648
Vector Pipeline L.P.
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	195	198
Maximum Exposure to Loss	392	301
Affiliate loan receivable	92	102
Credit facility provided	105
Other
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	57	27
Maximum Exposure to Loss	$ 57	$ 27

LONG-TERM INVESTMENTS - Schedul

LONG-TERM INVESTMENTS - Schedule of Long-Term Investments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2019
LONG-TERM INVESTMENTS
Total long-term investments	$ 16,707	$ 16,528
Enbridge Renewable Infrastructure Investments S.a.r.l. (ERII) | Canada Pension Plan Investment Board (CPPIB)
LONG-TERM INVESTMENTS
Ownership interest sold (percent)	49.00%
Direct common interest (as a percent)	25.50%
Noverco | Gas Distribution and Storage | Preference shares
LONG-TERM INVESTMENTS
OTHER LONG-TERM INVESTMENTS	$ 478	$ 580
Gray Oak Holdings LLC
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	35.00%
Gray Oak Crude Oil Pipeline
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	22.80%
MarEn Bakken Company L.L.C. | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		75.00%
EQUITY INVESTMENTS	$ 2,039	$ 1,892
MarEn Bakken Company L.L.C. | Bakken Pipeline Investments, LLC
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		49.00%
MarEn Bakken Company L.L.C. | Bakken Pipeline System
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		27.60%
Bakken Pipeline Investments, LLC | Bakken Pipeline System
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		75.00%
Gray Oak Holdings LLC | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		35.00%
EQUITY INVESTMENTS	0	$ 463
Seaway Crude Pipeline System | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		50.00%
EQUITY INVESTMENTS	3,113	$ 2,907
Illinois Extension Pipeline Company, L.L.C. | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		65.00%
EQUITY INVESTMENTS	724	$ 662
Other equity investments | Liquids Pipelines
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	97	$ 73
Other equity investments | Liquids Pipelines | Minimum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		30.00%
Other equity investments | Liquids Pipelines | Maximum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		43.80%
Other equity investments | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	6	$ 5
Other equity investments | Gas Transmission and Midstream | Minimum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		33.30%
Other equity investments | Gas Transmission and Midstream | Maximum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		50.00%
Other equity investments | Gas Distribution and Storage | Common Shares
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		50.00%
EQUITY INVESTMENTS	15	$ 14
Other equity investments | Renewable Power Generation
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	72	$ 127
Other equity investments | Renewable Power Generation | Minimum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		21.00%
Other equity investments | Renewable Power Generation | Maximum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		50.00%
Other equity investments | Eliminations and Other
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	10	$ 16
Other equity investments | Eliminations and Other | Minimum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		42.70%
Other equity investments | Eliminations and Other | Maximum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		50.00%
Alliance Pipeline | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		50.00%
EQUITY INVESTMENTS	368	$ 310
Aux Sable | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	311	$ 267
Aux Sable | Gas Transmission and Midstream | Minimum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		42.70%
Aux Sable | Gas Transmission and Midstream | Maximum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		50.00%
DCP Midstream, LLC | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		50.00%
EQUITY INVESTMENTS	2,368	$ 2,193
Gulfstream Natural Gas System, L.L.C. | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		50.00%
EQUITY INVESTMENTS	1,289	$ 1,213
Nexus Gas Transmission, LLC | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		50.00%
EQUITY INVESTMENTS	1,757	$ 1,778
Offshore - various joint ventures | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	400	$ 362
Offshore - various joint ventures | Gas Transmission and Midstream | Minimum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		22.00%
Offshore - various joint ventures | Gas Transmission and Midstream | Maximum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		74.30%
PennEast Pipeline Company, LLC | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		20.00%
EQUITY INVESTMENTS	97	$ 106
Sabal Trail Transmission, LLC | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		50.00%
EQUITY INVESTMENTS	1,586	$ 1,533
Southeast Supply Header L.L.C. | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		50.00%
EQUITY INVESTMENTS	519	$ 484
Steckman Ridge LP | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		49.50%
EQUITY INVESTMENTS	237	$ 222
Vector Pipeline L.P. | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		60.00%
EQUITY INVESTMENTS	$ 198	$ 195
Noverco | Gas Distribution and Storage | Common Shares
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	38.90%	38.90%
EQUITY INVESTMENTS	$ 0	$ 95
Eolien Maritime France SAS | Renewable Power Generation
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		50.00%
EQUITY INVESTMENTS	68	$ 67
Enbridge Renewable Infrastructure Investments S.a.r.l. (ERII) | Renewable Power Generation
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		51.00%
EQUITY INVESTMENTS	127	$ 141
Rampion Offshore Wind Project | Renewable Power Generation
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		24.90%
EQUITY INVESTMENTS	638	$ 600
Emerging Technologies and Other | Renewable Power Generation
LONG-TERM INVESTMENTS
OTHER LONG-TERM INVESTMENTS	80	78
Other long-term investments | Eliminations and Other
LONG-TERM INVESTMENTS
OTHER LONG-TERM INVESTMENTS	$ 110	$ 145

LONG-TERM INVESTMENTS - Summary

LONG-TERM INVESTMENTS - Summary of Combined Financial Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income statement information
Operating revenues	$ 15,687	$ 19,217	$ 16,213
Operating expenses	13,153	15,634	13,197
Earnings	3,016	2,954	2,728
Earnings attributable to Enbridge	1,359	1,382	1,262
Balance sheet information
Current assets	2,481	3,289
Non-current assets	48,942	49,116
Current liabilities	4,047	5,536
Non-current liabilities	18,126	15,875
Noncontrolling interests	2,779	3,479
Seaway
Income statement information
Operating revenues	1,252	966	959
Operating expenses	428	212	286
Earnings	818	646	672
Earnings attributable to Enbridge	409	323	336
Balance sheet information
Current assets	107	113
Non-current assets	3,404	3,585
Current liabilities	136	123
Non-current liabilities	45	16
Noncontrolling interests	0	0
Other
Income statement information
Operating revenues	14,435	18,251	15,254
Operating expenses	12,725	15,422	12,911
Earnings	2,198	2,308	2,056
Earnings attributable to Enbridge	950	1,059	$ 926
Balance sheet information
Current assets	2,374	3,176
Non-current assets	45,538	45,531
Current liabilities	3,911	5,413
Non-current liabilities	18,081	15,859
Noncontrolling interests	$ 2,779	$ 3,479

LONG-TERM INVESTMENTS - Narrati

LONG-TERM INVESTMENTS - Narrative (Details) - CAD ($) shares in Millions, $ in Millions	1 Months Ended		12 Months Ended
	Jan. 31, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Goodwill of investee		$ 2,200	$ 2,100	$ 2,200
Amortizable assets of investee		$ 706	681	706
Dividends received from equity investments			$ 2,200	$ 2,800	$ 1,400
Common Shares | Noverco
Schedule of Equity Method Investments [Line Items]
Reciprocal shareholding (as a percent)		1.40%	0.50%	1.40%
Equity Method Investment, number of shares sold (in shares)	11.6	4.4
Indirect pro-rata interest (as a percent)		0.50%	0.20%	0.50%
Reduction from reciprocal shareholding			$ 51	$ 88
Preference shares | Noverco
Schedule of Equity Method Investments [Line Items]
Maturity period			10 years
Margin (as a percent)			4.38%
Gas Distribution and Storage | Common Shares | Noverco
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)		38.90%	38.90%	38.90%

RESTRICTED LONG-TERM INVESTME_2

RESTRICTED LONG-TERM INVESTMENTS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Assets Held-in-trust [Abstract]
Restricted long-term investments	$ 434	$ 323
Future abandonment costs	$ 454	$ 328

INTANGIBLE ASSETS (Details)

INTANGIBLE ASSETS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
INTANGIBLE ASSETS
Cost	$ 3,532	$ 3,522
Accumulated Amortization	(1,359)	(1,150)
Net	2,173	2,372
Amortization expenses
Amortization expense for intangible assets	296	$ 281	$ 280
Expected amortization expense for intangible assets
2020	292
2021	263
2022	238
2023	216
2024	$ 195
Customer relationships
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	5.40%	5.70%
Cost	$ 861	$ 889
Accumulated Amortization	(231)	(187)
Net	$ 630	$ 702
Power purchase agreements
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	4.50%	5.40%
Cost	$ 64	$ 82
Accumulated Amortization	(16)	(15)
Net	$ 48	$ 67
Project agreement
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	4.00%	4.00%
Cost	$ 156	$ 164
Accumulated Amortization	(16)	(10)
Net	$ 140	$ 154
Software
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	11.20%	10.00%
Cost	$ 1,988	$ 1,902
Accumulated Amortization	(1,014)	(875)
Net	$ 974	$ 1,027
Other intangible assets
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	2.90%	2.00%
Cost	$ 463	$ 485
Accumulated Amortization	(82)	(63)
Net	$ 381	$ 422

GOODWILL (Details)

GOODWILL (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Gross Cost
Goodwill, gross at beginning of period	$ 36,040	$ 35,019
Disposition		(628)
Allocation to assets held for sale		(188)
Foreign exchange and other	(1,306)	1,837
Goodwill, gross at end of period	34,734	36,040	$ 35,019
Accumulated Impairment
Goodwill, impaired, accumulated impairment loss at beginning of period	(1,581)	(562)
Impairment	0	(1,019)	(102)
Goodwill, impaired, accumulated impairment loss at end of period	(1,581)	(1,581)	(562)
Goodwill	33,153	34,459
Eliminations and Other
Gross Cost
Goodwill, gross at beginning of period	13	13
Disposition		0
Allocation to assets held for sale		0
Foreign exchange and other	0	0
Goodwill, gross at end of period	13	13	13
Accumulated Impairment
Goodwill, impaired, accumulated impairment loss at beginning of period	(13)	(13)
Impairment	0	0	0
Goodwill, impaired, accumulated impairment loss at end of period	(13)	(13)	(13)
Goodwill	0	0
Liquids Pipelines
Gross Cost
Goodwill, gross at beginning of period	8,324	7,786
Disposition		0
Allocation to assets held for sale		0
Foreign exchange and other	(373)	538
Goodwill, gross at end of period	7,951	8,324	7,786
Accumulated Impairment
Goodwill, impaired, accumulated impairment loss at beginning of period	0	0
Impairment		0
Goodwill, impaired, accumulated impairment loss at end of period	0	0	0
Goodwill	7,951	8,324
Gas Transmission and Midstream
Gross Cost
Goodwill, gross at beginning of period	22,338	21,539
Disposition		(628)
Allocation to assets held for sale		(55)
Foreign exchange and other	(933)	1,482
Goodwill, gross at end of period	21,405	22,338	21,539
Accumulated Impairment
Goodwill, impaired, accumulated impairment loss at beginning of period	(1,561)	(542)
Impairment		(1,019)
Goodwill, impaired, accumulated impairment loss at end of period	(1,561)	(1,561)	(542)
Goodwill	19,844	20,777
Gas Distribution and Storage
Gross Cost
Goodwill, gross at beginning of period	5,363	5,679
Disposition		0
Allocation to assets held for sale		(133)
Foreign exchange and other	0	(183)
Goodwill, gross at end of period	5,363	5,363	5,679
Accumulated Impairment
Goodwill, impaired, accumulated impairment loss at beginning of period	(7)	(7)
Impairment		0
Goodwill, impaired, accumulated impairment loss at end of period	(7)	(7)	(7)
Goodwill	5,356	5,356
Renewable Power Generation
Gross Cost
Goodwill, gross at beginning of period	0	0
Disposition		0
Allocation to assets held for sale		0
Foreign exchange and other	0	0
Goodwill, gross at end of period	0	0	0
Accumulated Impairment
Goodwill, impaired, accumulated impairment loss at beginning of period	0	0
Impairment		0
Goodwill, impaired, accumulated impairment loss at end of period	0	0	0
Goodwill	0	0
Energy Services
Gross Cost
Goodwill, gross at beginning of period	2	2
Disposition		0
Allocation to assets held for sale		0
Foreign exchange and other	0	0
Goodwill, gross at end of period	2	2	2
Accumulated Impairment
Goodwill, impaired, accumulated impairment loss at beginning of period	0	0
Impairment		0
Goodwill, impaired, accumulated impairment loss at end of period	0	0	$ 0
Goodwill	$ 2	$ 2

GOODWILL - NARRATIVE (Details)

GOODWILL - NARRATIVE (Details) - CAD ($) $ in Millions	Jul. 04, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Feb. 27, 2017
GOODWILL
Impairment of goodwill		$ 0	$ 1,019	$ 102
Goodwill		$ 33,153	34,459
Spectra Energy Corp
GOODWILL
Goodwill				$ 36,700	$ 36,656
Dispositions | Midcoast Operating L.P.
GOODWILL
Goodwill, write of due to deconsolidation			262
Dispositions | Canadian Natural Gas Gathering and Processing Business
GOODWILL
Impairment of goodwill	$ 1,019
Goodwill, write of due to deconsolidation			$ 366

ACCOUNTS PAYABLE AND OTHER (Det

ACCOUNTS PAYABLE AND OTHER (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Payables and Accruals [Abstract]
Trade payables and operating accrued liabilities	$ 4,536	$ 4,604
Construction payables and contractor holdbacks	804	804
Current derivative liabilities	920	1,234
Dividends payable	1,678	1,539
Taxes payable	890	801
Current deferred credits	652	850
Other	583	31
Accounts payable and other liabilities	$ 10,063	$ 9,863

DEBT - Schedule of Debt (Detail

DEBT - Schedule of Debt (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)
DEBT
Total debt		$ 64,963		$ 64,610
Fair value adjustment - Merger Transaction		844		964
Other		(369)		(348)
Current maturities		(4,404)		(3,259)
Short-term borrowings		(898)		(1,024)
Long-term debt		$ 59,661		$ 60,327
Weighted average interest rate (as a percent)	2.00%	2.00%	2.30%	2.30%
United States dollar term notes | Enbridge Inc.
DEBT
Weighted Average Interest Rate	3.80%	3.80%
Total debt	$ 6,700	$ 8,689	$ 4,700	$ 6,419
Medium-term notes | Enbridge Gas Distribution Inc.
DEBT
Weighted Average Interest Rate
Total debt		$ 0		3,695
Medium-term notes | Enbridge Gas Inc.
DEBT
Weighted Average Interest Rate	4.20%	4.20%
Total debt		$ 7,685		0
Medium-term notes | Enbridge Pipelines Inc.
DEBT
Weighted Average Interest Rate	4.20%	4.20%
Total debt		$ 5,125		4,225
Carrying value		$ 100
Medium-term notes | Union Gas Limited
DEBT
Weighted Average Interest Rate
Total debt		$ 0		3,290
Medium-term notes | Westcoast Energy Inc.
DEBT
Weighted Average Interest Rate	4.50%	4.50%
Total debt		$ 1,875		2,175
Medium-term notes | Enbridge Inc.
DEBT
Weighted Average Interest Rate	4.20%	4.20%
Total debt		$ 7,623		7,323
Fixed-to-floating subordinated term notes | Enbridge Inc.
DEBT
Weighted Average Interest Rate	5.90%	5.90%
Total debt	$ 3,200	$ 6,550	3,200	6,771
Term of fixed rate	10 years
Carrying value		2,400		2,400
Floating rate notes | Spectra Energy Partners, LP
DEBT
Total debt	$ 400	519	400	546
Floating rate notes | Enbridge Inc.
DEBT
Total debt		1,556		2,389
Carrying value	$ 1,200		1,200	750
Commercial paper and credit facility draws
DEBT
Long-term debt		$ 8,974		7,967
Commercial paper and credit facility draws | Enbridge (U.S.) Inc.
DEBT
Weighted Average Interest Rate	2.10%	2.10%
Total debt	$ 1,337	$ 1,734	780	1,065
Commercial paper and credit facility draws | Enbridge Energy Partners, L.P.
DEBT
Total debt		$ 0	764	1,044
Commercial paper and credit facility draws | Enbridge Gas Distribution Inc.
DEBT
Weighted Average Interest Rate
Total debt		$ 0		750
Commercial paper and credit facility draws | Enbridge Gas Inc.
DEBT
Weighted Average Interest Rate	2.00%	2.00%
Total debt		$ 898		0
Commercial paper and credit facility draws | Enbridge Pipelines Inc.
DEBT
Weighted Average Interest Rate	2.00%	2.00%
Total debt	$ 355	$ 2,030	216	2,200
Draws		1,570		1,905
Commercial paper and credit facility draws | Spectra Energy Partners, LP
DEBT
Total debt		$ 0	1,512	2,065
Commercial paper and credit facility draws | Union Gas Limited
DEBT
Weighted Average Interest Rate
Total debt		$ 0		275
Commercial paper and credit facility draws | Enbridge Inc.
DEBT
Weighted Average Interest Rate	1.90%	1.90%
Total debt		$ 5,210		1,999
Carrying value			69
Draws		5,210		1,906
Other | Enbridge Inc.
DEBT
Total debt		$ 5		4
Senior notes | Enbridge Energy Partners, L.P.
DEBT
Weighted Average Interest Rate	6.00%	6.00%
Total debt	$ 3,050	$ 3,955	4,550	6,214
Senior notes | Enbridge Pipelines (Southern Lights) L.L.C.
DEBT
Weighted Average Interest Rate	4.00%	4.00%
Total debt	$ 871	$ 1,129	920	1,257
Senior notes | Enbridge Southern Lights LP
DEBT
Weighted Average Interest Rate	4.00%	4.00%
Total debt		$ 272		289
Senior notes | Spectra Energy Capital, LLC
DEBT
Weighted Average Interest Rate	7.10%	7.10%
Total debt	$ 173	$ 224	173	236
Senior notes | Spectra Energy Partners, LP
DEBT
Weighted Average Interest Rate	4.20%	4.20%
Total debt	$ 6,540	$ 8,481	6,040	8,249
Junior subordinated notes | Enbridge Energy Partners, L.P.
DEBT
Total debt		$ 0	400	546
Debentures | Enbridge Gas Distribution Inc.
DEBT
Weighted Average Interest Rate
Total debt		$ 0		85
Debentures | Enbridge Gas Inc.
DEBT
Weighted Average Interest Rate	9.10%	9.10%
Total debt		$ 210		0
Debentures | Enbridge Pipelines Inc.
DEBT
Weighted Average Interest Rate	8.20%	8.20%
Total debt		$ 200		200
Debentures | Union Gas Limited
DEBT
Weighted Average Interest Rate
Total debt		$ 0		125
Debentures | Westcoast Energy Inc.
DEBT
Weighted Average Interest Rate	8.60%	8.60%
Total debt		$ 375		375
Senior secured notes | Spectra Energy Partners, LP
DEBT
Weighted Average Interest Rate	6.10%	6.10%
Total debt	$ 110	$ 143	$ 110	150
Senior secured notes | Westcoast Energy Inc.
DEBT
Weighted Average Interest Rate
Total debt		$ 0		$ 33
Bankers' Acceptance Rate | Floating rate notes
DEBT
Basis spread on variable rate (as a percent)	0.59%
London Interbank Offered Rate (LIBOR) | Minimum | Floating rate notes
DEBT
Basis spread on variable rate (as a percent)	0.40%
London Interbank Offered Rate (LIBOR) | Maximum | Floating rate notes
DEBT
Basis spread on variable rate (as a percent)	0.70%

DEBT - Secured Debt (Narrative)

DEBT - Secured Debt (Narrative) (Details) $ in Millions	Dec. 31, 2019CAD ($)
Debt Disclosure [Abstract]
Senior secured notes	$ 143

DEBT - Schedule of Committed Cr

DEBT - Schedule of Committed Credit Facilities (Details) - Committed credit facilities $ in Millions	Dec. 31, 2019CAD ($)
DEBT
Total Facilities	$ 19,125
Draws	9,872
Available	9,253
Enbridge (U.S.) Inc.
DEBT
Total Facilities	7,132
Draws	1,734
Available	5,398
Enbridge Pipelines Inc.
DEBT
Total Facilities	3,000
Draws	2,030
Available	970
Union Gas Limited
DEBT
Total Facilities	2,000
Draws	898
Available	1,102
Enbridge Inc.
DEBT
Total Facilities	6,993
Draws	5,210
Available	$ 1,783

DEBT - Credit Facilities (Narra

DEBT - Credit Facilities (Narrative) (Details)	Jul. 18, 2019CAD ($)	May 16, 2019CAD ($)	Feb. 08, 2019CAD ($)	Dec. 31, 2019CAD ($)	May 16, 2019JPY (¥)	Dec. 31, 2018CAD ($)
Line of Credit Facility [Line Items]
Line of credit facility, increase (decrease)			$ 444,000,000
Weighted average standby fee (as a percent)				0.10%
Long-term debt				$ 59,661,000,000		$ 60,327,000,000
Commercial paper and credit facility draws
Line of Credit Facility [Line Items]
Long-term debt				8,974,000,000		7,967,000,000
Extendible credit facility
Line of Credit Facility [Line Items]
Term of credit facility		3 years
Credit facility capacity		$ 641,000,000			¥ 52,500,000,000
Non-revolving, bilateral credit facility
Line of Credit Facility [Line Items]
Term of credit facility	5 years
Credit facility capacity	$ 500,000,000
Uncommitted credit facilities
Line of Credit Facility [Line Items]
Credit facility capacity				916,000,000		807,000,000
Unutilized credit facility				$ 476,000,000		$ 548,000,000

DEBT - Schedule of Long-term De

DEBT - Schedule of Long-term Debt Issuances (Details)	1 Months Ended
	Apr. 30, 2018USD ($)	Mar. 31, 2018USD ($)	Nov. 30, 2019USD ($)	Oct. 31, 2019CAD ($)	Aug. 31, 2019USD ($)	Aug. 31, 2019CAD ($)	Feb. 28, 2019CAD ($)	Apr. 30, 2018CAD ($)	Jan. 31, 2018USD ($)
Enbridge Gas Distribution Inc. | 2.37% medium-term notes due August 2029
Debt Instrument [Line Items]
Principal Amount						$ 400,000,000
Fixed interest rate (as a percent)					2.37%	2.37%
Enbridge Gas Distribution Inc. | 3.01% medium-term notes due August 2049
Debt Instrument [Line Items]
Principal Amount						$ 300,000,000
Fixed interest rate (as a percent)					3.01%	3.01%
Enbridge Pipelines Inc. | 3.52% medium-term notes due February 2029
Debt Instrument [Line Items]
Principal Amount							$ 600,000,000
Fixed interest rate (as a percent)							3.52%
Enbridge Pipelines Inc. | 4.33% medium-term notes due February 2049
Debt Instrument [Line Items]
Principal Amount							$ 600,000,000
Fixed interest rate (as a percent)							4.33%
Spectra Energy Partners, LP | 3.24% senior notes due August 20294
Debt Instrument [Line Items]
Principal Amount					$ 500,000,000
Fixed interest rate (as a percent)					3.24%	3.24%
Spectra Energy Partners, LP | 3.50% senior notes due January 20285
Debt Instrument [Line Items]
Principal Amount									$ 400,000,000
Fixed interest rate (as a percent)									3.50%
Spectra Energy Partners, LP | 4.15% senior notes due January 20485
Debt Instrument [Line Items]
Principal Amount									$ 400,000,000
Fixed interest rate (as a percent)									4.15%
Enbridge Inc. | 2.99% medium-term notes due October 2029
Debt Instrument [Line Items]
Principal Amount				$ 1,000,000,000
Fixed interest rate (as a percent)				2.99%
Enbridge Inc. | 2.50% senior notes due July 2025
Debt Instrument [Line Items]
Principal Amount			$ 500,000,000
Fixed interest rate (as a percent)			2.50%
Enbridge Inc. | 3.13% senior notes due November 2029
Debt Instrument [Line Items]
Principal Amount			$ 1,000,000,000
Fixed interest rate (as a percent)			3.13%
Enbridge Inc. | 4.00% senior notes due November 2049
Debt Instrument [Line Items]
Principal Amount			$ 500,000,000
Fixed interest rate (as a percent)			4.00%
Enbridge Inc. | Fixed-to-floating rate subordinated notes due March 20781
Debt Instrument [Line Items]
Principal Amount		$ 850,000,000
Term of credit facility		60 years
Callable period		10 years
Term of fixed rate		10 years
Fixed interest rate (as a percent)		6.25%
Enbridge Inc. | Fixed-to-floating rate subordinated notes due April 20782
Debt Instrument [Line Items]
Principal Amount								$ 750,000,000
Term of credit facility	60 years
Callable period	10 years
Term of fixed rate	10 years
Fixed interest rate (as a percent)	6.625%							6.625%
Enbridge Inc. | Fixed-to-floating rate subordinated notes due April 20783
Debt Instrument [Line Items]
Principal Amount	$ 600,000,000
Term of credit facility	60 years
Callable period	5 years
Term of fixed rate	5 years
Fixed interest rate (as a percent)	6.375%							6.375%
Debt Instrument, Redemption, Period One | Enbridge Inc. | Fixed-to-floating rate subordinated notes due March 20781
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)		3.64%
Debt Instrument, Redemption, Period One | Enbridge Inc. | Fixed-to-floating rate subordinated notes due April 20782
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	4.32%
Debt Instrument, Redemption, Period One | Enbridge Inc. | Fixed-to-floating rate subordinated notes due April 20783
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	3.59%
Debt Instrument, Redemption, Period One | Minimum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due March 20781
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate		10 years
Debt Instrument, Redemption, Period One | Minimum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due April 20782
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate	10 years
Debt Instrument, Redemption, Period One | Minimum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due April 20783
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate	5 years
Debt Instrument, Redemption, Period One | Maximum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due March 20781
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate		30 years
Debt Instrument, Redemption, Period One | Maximum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due April 20782
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate	30 years
Debt Instrument, Redemption, Period One | Maximum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due April 20783
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate	10 years
Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed-to-floating rate subordinated notes due March 20781
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)		4.39%
Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed-to-floating rate subordinated notes due April 20782
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	5.07%
Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed-to-floating rate subordinated notes due April 20783
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	3.84%
Debt Instrument, Redemption, Period Two | Minimum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due March 20781
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate		30 years
Debt Instrument, Redemption, Period Two | Minimum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due April 20782
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate	30 years
Debt Instrument, Redemption, Period Two | Minimum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due April 20783
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate	10 years
Debt Instrument, Redemption, Period Two | Maximum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due March 20781
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate		60 years
Debt Instrument, Redemption, Period Two | Maximum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due April 20782
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate	60 years
Debt Instrument, Redemption, Period Two | Maximum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due April 20783
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate	25 years
Debt Instrument, Redemption, Period Three | Enbridge Inc. | Fixed-to-floating rate subordinated notes due April 20783
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	4.59%
Debt Instrument, Redemption, Period Three | Minimum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due April 20783
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate	25 years
Debt Instrument, Redemption, Period Three | Maximum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due April 20783
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate	60 years

DEBT - Schedule of Long-Term _2

DEBT - Schedule of Long-Term Debt Repayments (Details) $ in Millions, $ in Millions	1 Months Ended																				6 Months Ended	7 Months Ended				12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Nov. 30, 2019CAD ($)	Sep. 30, 2019USD ($)	May 31, 2019USD ($)	Mar. 31, 2019USD ($)	Feb. 28, 2019USD ($)	Feb. 28, 2019CAD ($)	Jan. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Nov. 30, 2018CAD ($)	Oct. 31, 2018USD ($)	Oct. 31, 2018CAD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2018CAD ($)	Aug. 31, 2018CAD ($)	Jul. 31, 2018USD ($)	Apr. 30, 2018USD ($)	Apr. 30, 2018CAD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)	Nov. 30, 2019CAD ($)	Dec. 31, 2018USD ($)	Nov. 30, 2018CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)
Enbridge Energy Partners, L.P. | 8.05% fixed/floating rate junior subordinated notes due 2067
Debt Instrument [Line Items]
Interest rate (percent)							8.05%	8.05%
Extinguishment of debt							$ 400
Enbridge Energy Partners, L.P. | 5.20% senior notes due 2020
Debt Instrument [Line Items]
Interest rate (percent)	5.20%	5.20%																			5.20%	5.20%				5.20%	5.20%
Extinguishment of debt	$ 500
Cash Consideration	$ 504
Enbridge Energy Partners, L.P. | 4.38% senior notes due 2020
Debt Instrument [Line Items]
Interest rate (percent)	4.38%	4.38%																			4.38%	4.38%				4.38%	4.38%
Extinguishment of debt	$ 500
Cash Consideration	$ 509
Enbridge Energy Partners, L.P. | 9.88% senior notes
Debt Instrument [Line Items]
Interest rate (percent)						9.88%
Extinguishment of debt						$ 500
Enbridge Energy Partners, L.P. | 6.50% senior notes
Debt Instrument [Line Items]
Interest rate (percent)																		6.50%	6.50%
Extinguishment of debt																		$ 400
Enbridge Energy Partners, L.P. | 7.00% senior notes
Debt Instrument [Line Items]
Interest rate (percent)												7.00%	7.00%
Extinguishment of debt												$ 100
Enbridge Income Fund | 4.00% medium-term notes
Debt Instrument [Line Items]
Interest rate (percent)										4.00%														4.00%				4.00%
Extinguishment of debt										$ 125
Enbridge Pipelines (Southern Lights) L.L.C. | 3.98% senior notes due 2040
Debt Instrument [Line Items]
Interest rate (percent)	3.98%	3.98%								3.98%											3.98%	3.98%		3.98%		3.98%	3.98%	3.98%
Extinguishment of debt																						$ 49		$ 43
Enbridge Pipelines Inc. | 4.49% medium-term notes
Debt Instrument [Line Items]
Interest rate (percent)			4.49%																				4.49%
Extinguishment of debt			$ 200
Enbridge Pipelines Inc. | 4.49% medium-term notes
Debt Instrument [Line Items]
Interest rate (percent)			4.49%																				4.49%
Extinguishment of debt			$ 100
Enbridge Pipelines Inc. | 6.62% medium-term notes
Debt Instrument [Line Items]
Interest rate (percent)											6.62%														6.62%
Extinguishment of debt											$ 170
Enbridge Pipelines Inc. | 6.62% medium-term notes
Debt Instrument [Line Items]
Interest rate (percent)											6.62%														6.62%
Extinguishment of debt											$ 130
Enbridge Southern Lights LP | 4.01% senior notes due 2040
Debt Instrument [Line Items]
Interest rate (percent)	4.01%	4.01%																			4.01%	4.01%				4.01%	4.01%
Extinguishment of debt																					$ 17
Enbridge Southern Lights LP | 4.01% senior notes due 2040
Debt Instrument [Line Items]
Interest rate (percent)										4.01%														4.01%				4.01%
Extinguishment of debt																												$ 27
Midcoast Energy Partner L.P. | 3.56% senior notes due 2019
Debt Instrument [Line Items]
Interest rate (percent)																	3.56%
Extinguishment of debt																	$ 75
Cash Consideration																	$ 76
Midcoast Energy Partner L.P. | 4.04% senior notes due 2021
Debt Instrument [Line Items]
Interest rate (percent)																	4.04%
Extinguishment of debt																	$ 175
Cash Consideration																	$ 182
Midcoast Energy Partner L.P. | 4.42% senior notes due 2024
Debt Instrument [Line Items]
Interest rate (percent)																	4.42%
Extinguishment of debt																	$ 150
Cash Consideration																	$ 161
Spectra Energy Capital, LLC
Debt Instrument [Line Items]
Loss on extinguishment of debt																										$ 50	$ 64
Spectra Energy Capital, LLC | 6.75% senior unsecured notes due 2032
Debt Instrument [Line Items]
Interest rate (percent)																				6.75%
Extinguishment of debt																				$ 64
Cash Consideration																				$ 80
Spectra Energy Capital, LLC | 7.50% senior unsecured notes due 2038
Debt Instrument [Line Items]
Interest rate (percent)																				7.50%
Extinguishment of debt																				$ 43
Cash Consideration																				$ 59
Spectra Energy Capital, LLC | 5.65% senior unsecured notes due 2020
Debt Instrument [Line Items]
Interest rate (percent)																				5.65%
Extinguishment of debt																				$ 163
Cash Consideration																				$ 172
Spectra Energy Capital, LLC | 3.30% senior unsecured notes due 2023
Debt Instrument [Line Items]
Interest rate (percent)																				3.30%
Extinguishment of debt																				$ 498
Cash Consideration																				$ 508
Spectra Energy Capital, LLC | 6.20% senior notes
Debt Instrument [Line Items]
Interest rate (percent)																		6.20%	6.20%
Extinguishment of debt																		$ 272
Spectra Energy Capital, LLC | 6.75% senior notes
Debt Instrument [Line Items]
Interest rate (percent)																	6.75%
Extinguishment of debt																	$ 118
Spectra Energy Partners, LP | 2.95% senior notes
Debt Instrument [Line Items]
Interest rate (percent)														2.95%	2.95%
Extinguishment of debt														$ 500
Union Gas Limited | 5.35% medium-term notes
Debt Instrument [Line Items]
Interest rate (percent)																		5.35%	5.35%
Extinguishment of debt																			$ 200
Union Gas Limited | 8.75% debentures
Debt Instrument [Line Items]
Interest rate (percent)																8.75%
Extinguishment of debt																$ 125
Union Gas Limited | 8.65% senior debentures
Debt Instrument [Line Items]
Interest rate (percent)												8.65%	8.65%
Extinguishment of debt													$ 75
Westcoast Energy Inc. | 5.60% medium-term notes
Debt Instrument [Line Items]
Interest rate (percent)									5.60%
Extinguishment of debt									$ 250
Westcoast Energy Inc. | 5.60% medium-term notes
Debt Instrument [Line Items]
Interest rate (percent)									5.60%
Extinguishment of debt									$ 50
Westcoast Energy Inc. | 6.90% senior secured notes
Debt Instrument [Line Items]
Interest rate (percent)			6.90%																				6.90%
Extinguishment of debt																							$ 26
Westcoast Energy Inc. | 4.34% senior secured notes
Debt Instrument [Line Items]
Interest rate (percent)			4.34%																				4.34%
Extinguishment of debt																							$ 5
Westcoast Energy Inc. | 1.00% senior secured notes
Debt Instrument [Line Items]
Interest rate (percent)			1.00%																				1.00%
Extinguishment of debt		$ 2
Westcoast Energy Inc. | 6.90% senior secured notes due 2019
Debt Instrument [Line Items]
Interest rate (percent)											6.90%														6.90%
Extinguishment of debt																									$ 26
Westcoast Energy Inc. | 4.34% senior secured notes due 2019
Debt Instrument [Line Items]
Interest rate (percent)											4.34%														4.34%
Extinguishment of debt																									$ 9
Westcoast Energy Inc. | 8.50% debentures
Debt Instrument [Line Items]
Interest rate (percent)														8.50%	8.50%
Extinguishment of debt															$ 150
Enbridge Inc. | 4.10% medium-term notes
Debt Instrument [Line Items]
Interest rate (percent)							4.10%	4.10%
Extinguishment of debt								$ 300
Enbridge Inc. | Floating rate notes
Debt Instrument [Line Items]
Interest rate (percent)				4.77%
Extinguishment of debt				$ 400
Enbridge Inc. | 5.60% medium-term notes
Debt Instrument [Line Items]
Extinguishment of debt					$ 750

DEBT - Schedule of Interest Exp

DEBT - Schedule of Interest Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
DEBT
Capitalized	$ (326)	$ (348)	$ (391)
Total interest expense	2,663	2,703	2,556
Spectra Energy Capital, LLC
DEBT
Amortization of fair value adjustment - Spectra Energy acquisition	(67)	(131)	(270)
Debentures and term notes
DEBT
Interest expense on debt	2,783	3,011	3,011
Commercial paper and credit facility draws
DEBT
Interest expense on debt	$ 273	$ 171	$ 206

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of movements in the Company's ARO
Obligations at beginning of year	$ 989	$ 793
Liabilities acquired	0	0
Liabilities disposed	(59)	(13)
Liabilities incurred	15	145
Liabilities settled	(12)	(21)
Change in estimate and other	(417)	29
Foreign currency translation adjustment	(18)	22
Accretion expense	22	34
Obligations at end of year	520	989
Accounts payable and other			$ 7	$ 6
Other long-term liabilities			513	983
Asset retirement obligations	$ 520	$ 793	$ 520	$ 989
Minimum
Asset Retirement Obligations [Line Items]
Discount rate (as a percent)	1.80%
Maximum
Asset Retirement Obligations [Line Items]
Discount rate (as a percent)	9.00%

NONCONTROLLING INTERESTS - NONC

NONCONTROLLING INTERESTS - NONCONTROLLING (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Aug. 01, 2018
NONCONTROLLING INTERESTS
Noncontrolling interests	$ 3,364	$ 3,965
Algonquin Gas Transmission LLC
NONCONTROLLING INTERESTS
Noncontrolling interests	394	518
Maritimes and Northeast Pipeline
NONCONTROLLING INTERESTS
Noncontrolling interests	579	613
Renewable energy assets
NONCONTROLLING INTERESTS
Noncontrolling interests	1,864	1,961
Westcoast Energy Inc.
NONCONTROLLING INTERESTS
Noncontrolling interests	527	841
Other Non Controlling Interest
NONCONTROLLING INTERESTS
Noncontrolling interests	$ 0	$ 32
Canadian Renewable Assets | Discontinued Operations, Disposed of by Sale
NONCONTROLLING INTERESTS
Noncontrolling interest, ownership percentage by parent			49.00%
Magic Valley
NONCONTROLLING INTERESTS
Ownership interest percentage held by noncontrolling owners	20.00%	20.00%
Maritimes and Northeast Pipeline
NONCONTROLLING INTERESTS
Ownership interest percentage held by noncontrolling owners	22.20%	22.20%
Cumulative redeemable preferred stock | Westcoast Energy Inc. | Preference shares
NONCONTROLLING INTERESTS
Number of redeemable preferred shares held by noncontrolling owners (in shares)	16,600,000	16,600,000
Cumulative first preferred stock | Westcoast Energy Inc. | Preference shares
NONCONTROLLING INTERESTS
Number of redeemable preferred shares held by noncontrolling owners (in shares)	0	12,000,000

NONCONTROLLING INTERESTS - NO_2

NONCONTROLLING INTERESTS - NONCONTROLLING INFORMATION (Details) $ / shares in Units, shares in Millions	Mar. 20, 2019CAD ($)$ / shares	Nov. 08, 2018CAD ($)	Sep. 17, 2018$ / shares	Aug. 24, 2018	Jan. 22, 2018shares	Apr. 28, 2017CAD ($)	Sep. 30, 2018CAD ($)	Dec. 31, 2019CAD ($)$ / shares	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Aug. 01, 2018	Dec. 31, 2016CAD ($)
NONCONTROLLING INTERESTS
Repurchase of noncontrolling interest	$ (300,000,000)								$ (4,469,000,000)	$ 0
Noncontrolling interests								$ 3,364,000,000	3,965,000,000
Redeemable noncontrolling interests									0	4,067,000,000		$ 3,392,000,000
Proceeds from issuance of preferred stock	300,000,000
Strategic Review Actions | Enbridge Energy Partners, L.P.
NONCONTROLLING INTERESTS
Decrease to additional paid in capital						$ 421,000,000
Increase (decrease) to deferred income taxes						253,000,000
Increase (decrease) in noncontrolling interest						$ 458,000,000
Spectra Energy Partners, LP
NONCONTROLLING INTERESTS
Security shareholders entitlement share ratio				1.111
Repurchase of noncontrolling interest									3,000,000,000
Decrease to additional paid in capital									642,000,000
Increase (decrease) to deferred income taxes									(167,000,000)
Enbridge Energy Partners, L.P.
NONCONTROLLING INTERESTS
Security shareholders entitlement share ratio			0.335
Enbridge Energy Management, L.L.C. (EEM)
NONCONTROLLING INTERESTS
Security shareholders entitlement share ratio			0.335
Enbridge Energy Partners and Enbridge Energy Management
NONCONTROLLING INTERESTS
Decrease to additional paid in capital									3,700,000,000
Increase (decrease) to deferred income taxes									(707,000,000)
Increase (decrease) in noncontrolling interest									185,000,000
Enbridge Income Fund
NONCONTROLLING INTERESTS
Security shareholders entitlement share ratio			0.735
Repurchase of noncontrolling interest		$ 4,500,000,000
Decrease to additional paid in capital		25,000,000
Increase (decrease) to deferred income taxes		0
Shareholder entitlement cash payment per share | $ / shares			$ 0.45
Common Shares
NONCONTROLLING INTERESTS
Common shares issued in acquisition, amount								0	12,727,000,000	0
Common Shares | Spectra Energy Partners, LP
NONCONTROLLING INTERESTS
Common shares issued in acquisition, amount								0	3,888,000,000	0
Common Shares | Enbridge Energy Partners, L.P.
NONCONTROLLING INTERESTS
Common shares issued in acquisition, amount								0	3,042,000,000	0
Common Shares | Enbridge Energy Management, L.L.C. (EEM)
NONCONTROLLING INTERESTS
Common shares issued in acquisition, amount								0	1,267,000,000	0
Common Shares | Enbridge Income Fund
NONCONTROLLING INTERESTS
Common shares issued in acquisition, amount		$ 4,500,000,000						0	4,530,000,000	0
Noncontrolling Interest
NONCONTROLLING INTERESTS
Repurchase of noncontrolling interest								(65,000,000)	0	0
Sale of noncontrolling interests in subsidiaries							$ 1,183,000,000	0	1,183,000,000	0
Noncontrolling interest, restructuring								0	1,486,000,000	0
Additional paid-in capital
NONCONTROLLING INTERESTS
Sale of noncontrolling interests in subsidiaries							79,000,000	0	79,000,000	0
Dilution gain on Spectra Energy Partners, LP restructuring (Note 20)								$ 0	$ 1,136,000,000	$ 0
Deferred Income Tax Liability
NONCONTROLLING INTERESTS
Sale of noncontrolling interests in subsidiaries							$ 27,000,000
Preference shares
NONCONTROLLING INTERESTS
Dividend payment	$ 4,000,000
Maritimes and Northeast Pipeline
NONCONTROLLING INTERESTS
Ownership interest percentage held by noncontrolling owners								22.20%	22.20%
Canadian Renewable Assets | Discontinued Operations, Disposed of by Sale
NONCONTROLLING INTERESTS
Noncontrolling interest, ownership percentage by parent											49.00%
United States Renewable Assets | Discontinued Operations, Disposed of by Sale
NONCONTROLLING INTERESTS
Noncontrolling interest, ownership percentage by parent											49.00%
Other Restructuring | Spectra Energy Partners, LP
NONCONTROLLING INTERESTS
Increase (decrease) to deferred income taxes									$ 333,000,000
Stock issued during period, shares, conversion of units (in shares) | shares					172.5
Noncontrolling interest, restructuring									1,500,000,000
Dilution gain on Spectra Energy Partners, LP restructuring (Note 20)									$ 1,100,000,000
Preference Shares, Series 7 | Preference shares
NONCONTROLLING INTERESTS
Dividend rate (percent)	5.50%							4.45%
Redemption price (in dollars per shares) | $ / shares	$ 25							$ 25
Series 8 Preferred Stock | Preference shares
NONCONTROLLING INTERESTS
Dividend rate (percent)	5.60%
Redemption price (in dollars per shares) | $ / shares	$ 25

NONCONTROLLING INTERESTS - REDE

NONCONTROLLING INTERESTS - REDEEMABLE NONCONTROLLING INFORMATION (Details) - CAD ($)	Mar. 20, 2019	Dec. 31, 2018	Dec. 31, 2017
REDEEMABLE NONCONTROLLING INTERESTS
Balance at beginning of year		$ 4,067,000,000	$ 3,392,000,000
Earnings attributable to redeemable noncontrolling interests		117,000,000	175,000,000
Change in unrealized loss on cash flow hedges		3,000,000	(21,000,000)
Other comprehensive loss from equity investees		14,000,000	0
Reclassification to earnings of loss on cash flow hedges		0	57,000,000
Foreign currency translation adjustments		4,000,000	(6,000,000)
Other comprehensive income/(loss)		21,000,000	30,000,000
Distributions to unitholders		(300,000,000)	(247,000,000)
Contributions from unitholders		70,000,000	1,178,000,000
Modified retrospective adoption of accounting standard		(38,000,000)	0
Dilution gain/(loss) for redeemable noncontrolling interests		76,000,000	(169,000,000)
Redemption value adjustment		456,000,000	(292,000,000)
Sponsored vehicle buy-in	$ (300,000,000)	(4,469,000,000)	0
Balance at end of year		$ 0	$ 4,067,000,000

SHARE CAPITAL - COMMON SHARES (

SHARE CAPITAL - COMMON SHARES (Details) - CAD ($) shares in Millions, $ in Millions	Nov. 08, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Common Shares
Balance at beginning of period (in shares)		2,022
Balance at end of period (in shares)		2,025	2,022
Common Shares
Common Shares
Balance at beginning of period (in shares)		2,022	1,695	943
Balance at beginning of period, Amount		$ 64,677	$ 50,737	$ 10,492
Common shares issued (in shares)		0	0	33
Common shares issued, Amount		$ 0	$ 0	$ 1,500
Common shares issued in acquisition, amount		$ 0	$ 12,727	$ 0
Dividend Reinvestment and Share Purchase Plan (in shares)		0	28	25
Dividend Reinvestment and Share Purchase Plan		$ 0	$ 1,181	$ 1,226
Shares issued on exercise of stock options (in shares)		3	2	3
Shares issued on exercise of stock options, Amount		$ 69	$ 32	$ 90
Balance at end of period (in shares)		2,025	2,022	1,695
Balance at end of period, Amount		$ 64,746	$ 64,677	$ 50,737
Merger Transaction | Common Shares
Common Shares
Common shares issued in acquisition (in shares)		0	0	691
Common shares issued in acquisition, amount		$ 0	$ 0	$ 37,429
Spectra Energy Partners, LP | Common Shares
Common Shares
Common shares issued in acquisition (in shares)		0	91	0
Common shares issued in acquisition, amount		$ 0	$ 3,888	$ 0
Enbridge Energy Partners, L.P. | Common Shares
Common Shares
Common shares issued in acquisition (in shares)		0	72	0
Common shares issued in acquisition, amount		$ 0	$ 3,042	$ 0
Enbridge Energy Management, L.L.C. (EEM) | Common Shares
Common Shares
Common shares issued in acquisition (in shares)		0	30	0
Common shares issued in acquisition, amount		$ 0	$ 1,267	$ 0
Enbridge Income Fund | Common Shares
Common Shares
Common shares issued in acquisition (in shares)		0	104	0
Common shares issued in acquisition, amount	$ 4,500	$ 0	$ 4,530	$ 0

SHARE CAPITAL - PREFERRED SHARE

SHARE CAPITAL - PREFERRED SHARES (Details) $ / shares in Units, shares in Millions, $ in Millions	Dec. 01, 2019$ / shares	Nov. 30, 2019$ / shares	Sep. 01, 2019$ / shares	Aug. 31, 2019$ / shares	Jun. 01, 2019$ / shares	May 31, 2019$ / shares	Mar. 20, 2019$ / shares	Mar. 01, 2019$ / shares	Mar. 01, 2019$ / shares	Feb. 28, 2019$ / shares	Feb. 28, 2019$ / shares	Dec. 31, 2019CAD ($)$ / sharesshares	Dec. 31, 2019CAD ($)$ / shares$ / sharesshares	Dec. 31, 2018CAD ($)shares	Dec. 31, 2017CAD ($)shares	Dec. 31, 2019$ / shares
Preference shares
Share Capital
Preferred stock, value, outstanding | $												$ 7,747	$ 7,747	$ 7,747	$ 7,747
Issuance costs | $												$ (155)		$ (155)	$ (155)
Recurring anniversary period following the redemption option date, at which the entity may redeem preferred shares												5 years
Stock split conversion ratio												1
Quarterly floating rate cumulative dividends per share calculation, base multiplier (in dollars per share) | (per share)												$ 25	$ 25
Quarterly floating rate cumulative dividends per share calculation, period of calendar year												365 days
Quarterly floating rate cumulative dividends per share calculation, maturity period of Government of Canada treasury bill												90 days
Preference Shares, Series A | Preference shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares												5	5	5	5
Preferred stock, value, outstanding | $												$ 125	$ 125	$ 125	$ 125
Initial Yield (as a percent)												5.50%
Yearly dividend per share (in dollars per share)												$ 1.37500
Per Share Base Redemption Value (in dollars per shares)												$ 25	$ 25
Preference Shares, Series B | Preference shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares												18	18	18	18
Preferred stock, value, outstanding | $												$ 457	$ 457	$ 457	$ 457
Initial Yield (as a percent)												3.42%
Yearly dividend per share (in dollars per share)												$ 0.85360
Per Share Base Redemption Value (in dollars per shares)												$ 25	$ 25
Preference Shares, Series C
Share Capital
Yearly dividend per share (in dollars per share)	$ 0.25305	$ 0.25243	$ 0.25243	$ 0.25647	$ 0.25647	$ 0.25395		$ 0.25395		$ 0.25459
Preference Shares, Series C | Preference shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares												2	2	2	2
Preferred stock, value, outstanding | $												$ 43	$ 43	$ 43	$ 43
Initial Yield (as a percent)												2.40%
Yearly dividend per share (in dollars per share)												$ 0
Per Share Base Redemption Value (in dollars per shares)												$ 25	$ 25
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)												2.40%
Preference Shares, Series D | Preference shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares												18	18	18	18
Preferred stock, value, outstanding | $												$ 450	$ 450	$ 450	$ 450
Initial Yield (as a percent)												4.46%
Yearly dividend per share (in dollars per share)												$ 1.11500
Per Share Base Redemption Value (in dollars per shares)												$ 25	$ 25
Preference Shares, Series F | Preference shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares												20	20	20	20
Preferred stock, value, outstanding | $												$ 500	$ 500	$ 500	$ 500
Initial Yield (as a percent)												4.69%
Yearly dividend per share (in dollars per share)												$ 1.17224
Per Share Base Redemption Value (in dollars per shares)												$ 25	$ 25
Preference Shares, Series H | Preference shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares												14	14	14	14
Preferred stock, value, outstanding | $												$ 350	$ 350	$ 350	$ 350
Initial Yield (as a percent)												4.38%
Yearly dividend per share (in dollars per share)												$ 1.09400
Per Share Base Redemption Value (in dollars per shares)												$ 25	$ 25
Preference Shares, Series J | Preference shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares												8	8	8	8
Preferred stock, value, outstanding | $												$ 199	$ 199	$ 199	$ 199
Initial Yield (as a percent)												4.89%
Yearly dividend per share (in dollars per share)													$ 1.22160
Per Share Base Redemption Value (in dollars per shares)																$ 25
Preference Shares, Series L | Preference shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares												16	16	16	16
Preferred stock, value, outstanding | $												$ 411	$ 411	$ 411	$ 411
Initial Yield (as a percent)												4.96%
Yearly dividend per share (in dollars per share)													$ 1.23972
Per Share Base Redemption Value (in dollars per shares)																25
Preference Shares, Series N | Preference shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares												18	18	18	18
Preferred stock, value, outstanding | $												$ 450	$ 450	$ 450	$ 450
Initial Yield (as a percent)												5.09%
Yearly dividend per share (in dollars per share)												$ 1.27152
Per Share Base Redemption Value (in dollars per shares)												$ 25	$ 25
Preference Shares, Series P
Share Capital
Yearly dividend per share (in dollars per share)								0.27369		0.25000
Preference Shares, Series P | Preference shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares												16	16	16	16
Preferred stock, value, outstanding | $												$ 400	$ 400	$ 400	$ 400
Initial Yield (as a percent)												4.38%
Yearly dividend per share (in dollars per share)												$ 1.09476
Per Share Base Redemption Value (in dollars per shares)												$ 25	$ 25
Preference Shares, Series R
Share Capital
Yearly dividend per share (in dollars per share)					$ 0.25456	$ 0.25000
Preference Shares, Series R | Preference shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares												16	16	16	16
Preferred stock, value, outstanding | $												$ 400	$ 400	$ 400	$ 400
Initial Yield (as a percent)												4.07%
Yearly dividend per share (in dollars per share)												$ 1.01825
Per Share Base Redemption Value (in dollars per shares)												$ 25	$ 25
Preference Shares, Series 1 | Preference shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares												16	16	16	16
Preferred stock, value, outstanding | $												$ 411	$ 411	$ 411	$ 411
Initial Yield (as a percent)												5.95%
Yearly dividend per share (in dollars per share)													$ 1.48728
Per Share Base Redemption Value (in dollars per shares)																25
Preference Shares, Series 3
Share Capital
Yearly dividend per share (in dollars per share)			$ 0.23356	$ 0.25000
Preference Shares, Series 3 | Preference shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares												24	24	24	24
Preferred stock, value, outstanding | $												$ 600	$ 600	$ 600	$ 600
Initial Yield (as a percent)												3.74%
Yearly dividend per share (in dollars per share)												$ 0.93425
Per Share Base Redemption Value (in dollars per shares)												$ 25	$ 25
Preference Shares, Series 5
Share Capital
Yearly dividend per share (in dollars per share)									$ 0.33625		$ 0.27500
Preference Shares, Series 5 | Preference shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares												8	8	8	8
Preferred stock, value, outstanding | $												$ 206	$ 206	$ 206	$ 206
Initial Yield (as a percent)												5.38%
Yearly dividend per share (in dollars per share)													$ 1.34383
Per Share Base Redemption Value (in dollars per shares)																$ 25
Preference Shares, Series 7
Share Capital
Yearly dividend per share (in dollars per share)								$ 0.27806		$ 0.27500
Preference Shares, Series 7 | Preference shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares												10	10	10	10
Preferred stock, value, outstanding | $												$ 250	$ 250	$ 250	$ 250
Initial Yield (as a percent)							5.50%					4.45%
Yearly dividend per share (in dollars per share)												$ 1.11224
Per Share Base Redemption Value (in dollars per shares)							$ 25					$ 25	$ 25
Preference Shares, Series 9
Share Capital
Yearly dividend per share (in dollars per share)	$ 0.25606	$ 0.27500
Preference Shares, Series 9 | Preference shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares												11	11	11	11
Preferred stock, value, outstanding | $												$ 275	$ 275	$ 275	$ 275
Initial Yield (as a percent)												4.10%
Yearly dividend per share (in dollars per share)												$ 1.02424
Per Share Base Redemption Value (in dollars per shares)												$ 25	$ 25
Preference Shares, Series 11 | Preference shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares												20	20	20	20
Preferred stock, value, outstanding | $												$ 500	$ 500	$ 500	$ 500
Initial Yield (as a percent)												4.40%
Yearly dividend per share (in dollars per share)												$ 1.10000
Per Share Base Redemption Value (in dollars per shares)												$ 25	$ 25
Preference Shares, Series 13 | Preference shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares												14	14	14	14
Preferred stock, value, outstanding | $												$ 350	$ 350	$ 350	$ 350
Initial Yield (as a percent)												4.40%
Yearly dividend per share (in dollars per share)												$ 1.10000
Per Share Base Redemption Value (in dollars per shares)												$ 25	$ 25
Preference Shares, Series 15 | Preference shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares												11	11	11	11
Preferred stock, value, outstanding | $												$ 275	$ 275	$ 275	$ 275
Initial Yield (as a percent)												4.40%
Yearly dividend per share (in dollars per share)												$ 1.10000
Per Share Base Redemption Value (in dollars per shares)												$ 25	$ 25
Preference Shares, Series 17 | Preference shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares												30	30	30	30
Preferred stock, value, outstanding | $												$ 750	$ 750	$ 750	$ 750
Initial Yield (as a percent)												5.15%
Yearly dividend per share (in dollars per share)												$ 1.28750
Per Share Base Redemption Value (in dollars per shares)												$ 25	$ 25
Minimum fixed dividend rate upon reset (as a percent)												5.15%
Preference Shares, Series 19 | Preference shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares												20	20	20	20
Preferred stock, value, outstanding | $												$ 500	$ 500	$ 500	$ 500
Initial Yield (as a percent)												4.90%
Yearly dividend per share (in dollars per share)												$ 1.22500
Per Share Base Redemption Value (in dollars per shares)												$ 25	$ 25
Minimum fixed dividend rate upon reset (as a percent)												4.90%
Preferred Stock Excluding Series | Preference shares
Share Capital
Reset term of fixed dividend rate												5 years
Preference Shares, Series E | Preference shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)												2.40%
Series G Preferred Stock | Preference shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)												2.50%
Series I Preferred Stock | Preference shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)												2.10%
Series O Preferred Stock | Preference shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)												2.70%
Series Q Preferred Stock | Preference shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)												2.50%
Series S Preferred Stock | Preference shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)												2.50%
Series 4 Preferred Stock | Preference shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)												2.40%
Series 8 Preferred Stock | Preference shares
Share Capital
Initial Yield (as a percent)							5.60%
Per Share Base Redemption Value (in dollars per shares)							$ 25
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)												2.60%
Series10 Preferred Stock | Preference shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)												2.70%
Series12 Preferred Stock | Preference shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)												2.60%
Series14 Preferred Stock | Preference shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)												2.70%
Series16 Preferred Stock | Preference shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)												2.70%
Series18 Preferred Stock | Preference shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)												4.10%
Series 20 Preferred Stock | Preference shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)												3.20%
Series K Preferred Stock | Preference shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of US treasury bill rate (as a percent)												3.10%
Series M Preferred Stock | Preference shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of US treasury bill rate (as a percent)												3.20%
Series 2 Preferred Stock | Preference shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of US treasury bill rate (as a percent)												3.10%
Series 6 Preferred Stock | Preference shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of US treasury bill rate (as a percent)												2.80%

SHARE CAPITAL - PLANS (Details)

SHARE CAPITAL - PLANS (Details)	Dec. 31, 2019	Nov. 02, 2018
Equity [Abstract]
Discount on the purchase of common shares with reinvested dividends (as a percent)		2.00%
Minimum outstanding common shares required to be acquired to exercise the Shareholder Rights Plan (as a percent)	20.00%
Discount to the market price available to each rights holder, other than the acquiring person and related parties, under the Shareholder Rights Plan (as a percent)	50.00%

STOCK OPTION AND STOCK UNIT P_3

STOCK OPTION AND STOCK UNIT PLANS - INCENTIVE PLANS (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)compensation_planshares	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Feb. 13, 2019shares
STOCK OPTION AND STOCK UNIT PLANS
Number of long-term incentive compensation plans | compensation_plan	4
Compensation expense | $	$ 117	$ 106	$ 165
PSU and RSU plans
STOCK OPTION AND STOCK UNIT PLANS
Maximum number of common shares reserved for issuance under the share-based compensation plan (in shares)				50,000,000
Number of common shares for each stock unit granted (in shares)	1

STOCK OPTION AND STOCK UNIT P_4

STOCK OPTION AND STOCK UNIT PLANS - STOCK OPTION ACTIVITY (Details) - INCENTIVE STOCK OPTIONS - CAD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
STOCK OPTION AND STOCK UNIT PLANS
Vesting period	4 years
Expiration term	10 years
Number
Options outstanding at beginning of year (in shares)	34,387
Options granted (in shares)	6,777
Options exercised (in shares)	(4,519)
Options cancelled or expired (in shares)	(1,598)
Options outstanding at end of year (in shares)	35,047	34,387
Options vested at end of year (in shares)	20,581
Weighted Average Exercise Price
Options outstanding at beginning of year (in dollars per share)	$ 43.47
Options granted (in dollars per share)	48.32
Options exercised (in dollars per share)	34.19
Options cancelled or expired (in dollars per share)	50.62
Options outstanding at end of year (in dollars per share)	47.73	$ 43.47
Options vested at end of year (in dollars per share)	$ 47.67
Weighted Average Remaining Contractual Life (years)
Options outstanding at end of year	6 years 2 months 12 days
Options vested at end of year	4 years 8 months 12 days
Aggregate Intrinsic Value
Options outstanding at end of year	$ 157
Options vested at end of year	92
Stock options, additional disclosures
Total intrinsic value of awards exercised	58	$ 42	$ 62
Cash received on exercise of awards	1	15	17
Total fair value of options vested	$ 32	$ 36	$ 44

STOCK OPTION AND STOCK UNIT P_5

STOCK OPTION AND STOCK UNIT PLANS - WEIGHTED AVERAGE ASSUMPTIONS (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)$ / shares	Dec. 31, 2018CAD ($)$ / shares	Dec. 31, 2017CAD ($)$ / shares	Dec. 31, 2019$ / shares	Dec. 31, 2018$ / shares	Dec. 31, 2017$ / shares
Weighted average assumptions used to determine the fair value of options
Compensation expense | $	$ 117	$ 106	$ 165
INCENTIVE STOCK OPTIONS
Weighted average assumptions used to determine the fair value of options
Fair value per option (in dollars per share) | $ / shares	$ 4.37	$ 3.86	$ 6
Expected option term (in years)	5 years	5 years	5 years
Expected volatility (as a percent)	19.90%	21.90%	20.40%
Expected dividend yield (as a percent)	6.10%	6.40%	4.40%
Risk-free interest rate (as a percent)	2.00%	2.20%	1.20%
Expected option term - historical exercise practice	6 years
Compensation expense | $	$ 32	$ 28	$ 40
Unrecognized compensation cost related to non-vested share-based compensation arrangements granted | $	$ 18
Weighted average period over which compensation cost is expected to be recognized	2 years
INCENTIVE STOCK OPTIONS | Canadian employees
Weighted average assumptions used to determine the fair value of options
Fair value per option (in dollars per share) | $ / shares	$ 4.04	$ 3.75	$ 5.66
INCENTIVE STOCK OPTIONS | United States employees
Weighted average assumptions used to determine the fair value of options
Fair value per option (in dollars per share) | $ / shares				$ 4.09	$ 3.30	$ 5.72
INCENTIVE STOCK OPTIONS | Retirement-eligible employees
Weighted average assumptions used to determine the fair value of options
Expected option term (in years)	3 years

STOCK OPTION AND STOCK UNIT P_6

STOCK OPTION AND STOCK UNIT PLANS - PSUs AND RSUs (Details) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)shares	Dec. 31, 2018CAD ($)shares	Dec. 31, 2017CAD ($)
Stock units, additional disclosures
Compensation expense | $	$ 117	$ 106	$ 165
Performance Stock Units (PSUs)
STOCK OPTION AND STOCK UNIT PLANS
Performance / maturity period	3 years
Period prior to the maturity of the grant for which weighted average share price is used to calculate cash awards	20 days
Performance multiplier	1
Number
Units outstanding at beginning of year (in shares)	1,069
Units granted (in shares)	1,093
Units cancelled (in shares)	(65)
Units matured (in shares)	(25)
Dividend reinvestment (in shares)	117
Units outstanding at end of year (in shares)	2,189	1,069
Weighted Average Remaining Contractual Life (years)
Units outstanding at end of year	1 year 6 months
Aggregate Intrinsic Value
Units outstanding at end of year | $	$ 111
Stock units, additional disclosures
Total amount paid | $	19	$ 18	28
Compensation expense | $	40	$ 15	5
Unrecognized compensation expense related to non-vested units granted | $	$ 55
Weighted average period over which compensation cost is expected to be recognized	2 years
Restricted Stock Units (RSU)
STOCK OPTION AND STOCK UNIT PLANS
Performance / maturity period	35 months
Period prior to the maturity of the grant for which weighted average share price is used to calculate cash awards	20 days
Number
Units outstanding at beginning of year (in shares)	1,213
Units granted (in shares)	1,087
Units cancelled (in shares)	(96)
Units matured (in shares)	(706)
Dividend reinvestment (in shares)	126
Units outstanding at end of year (in shares)	1,624	1,213
Weighted Average Remaining Contractual Life (years)
Units outstanding at end of year	1 year 7 months 6 days
Aggregate Intrinsic Value
Units outstanding at end of year | $	$ 82
Stock units, additional disclosures
Total amount paid | $	34	$ 41	39
Compensation expense | $	41	$ 32	$ 46
Unrecognized compensation expense related to non-vested units granted | $	$ 47
Weighted average period over which compensation cost is expected to be recognized	2 years
Minimum | Performance Stock Units (PSUs)
STOCK OPTION AND STOCK UNIT PLANS
Performance multiplier	0
Maximum | Performance Stock Units (PSUs)
STOCK OPTION AND STOCK UNIT PLANS
Performance multiplier	2

COMPONENTS OF ACCUMULATED OTH_3

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Components of accumulated other comprehensive loss
Balance	$ 73,435	$ 65,732
Other comprehensive income/(loss) retained in AOCI	(3,296)	3,479	$ (2,137)
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	17	16	41
Other comprehensive (income)/loss reclassified to earnings	(3,121)	3,680	(1,908)
Income tax on amounts retained in AOCI	164	148	(30)
Income tax on amounts reclassified to earnings	(35)	(41)	(93)
Tax impact	129	107	(123)
Other	48	(142)
Balance	69,407	73,435	65,732
Interest rate contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	157	157	207
Commodity contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	(1)	(1)	(7)
Forward exchange contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	5	7	(6)
Other contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	(3)	22	(6)
Cash Flow Hedges
Components of accumulated other comprehensive loss
Balance	(770)	(644)	(746)
Other comprehensive income/(loss) retained in AOCI	(599)	(244)	1
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	(441)	(59)	189
Income tax on amounts retained in AOCI	169	57	(16)
Income tax on amounts reclassified to earnings	(31)	(37)	(71)
Tax impact	138	20	(87)
Other		(87)
Balance	(1,073)	(770)	(644)
Cash Flow Hedges | Interest rate contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	157	157	207
Cash Flow Hedges | Commodity contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	(1)	(1)	(7)
Cash Flow Hedges | Forward exchange contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	5	7	(6)
Cash Flow Hedges | Other contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	(3)	22	(6)
Net Investment Hedges
Components of accumulated other comprehensive loss
Balance	(598)	(139)	(629)
Other comprehensive income/(loss) retained in AOCI	320	(509)	478
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	320	(509)	478
Income tax on amounts retained in AOCI	(39)	50	12
Tax impact	(39)	50	12
Balance	(317)	(598)	(139)
Cumulative Translation Adjustment
Components of accumulated other comprehensive loss
Balance	4,323	77	2,700
Other comprehensive income/(loss) retained in AOCI	(2,927)	4,301	(2,623)
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	(2,927)	4,301	(2,623)
Other		(55)
Balance	1,396	4,323	77
Equity Investees
Components of accumulated other comprehensive loss
Balance	34	10	37
Other comprehensive income/(loss) retained in AOCI	34	16	(11)
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	34	16	(11)
Income tax on amounts retained in AOCI	6	8	(16)
Tax impact	6	8	(16)
Other	(7)
Balance	67	34	10
Pension and OPEB Adjustment
Components of accumulated other comprehensive loss
Balance	(317)	(277)	(304)
Other comprehensive income/(loss) retained in AOCI	(124)	(85)	18
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	17	16	41
Other comprehensive (income)/loss reclassified to earnings	(107)	(69)	59
Income tax on amounts retained in AOCI	28	33	(10)
Income tax on amounts reclassified to earnings	(4)	(4)	(22)
Tax impact	24	29	(32)
Other	55	0
Balance	(345)	(317)	(277)
Total
Components of accumulated other comprehensive loss
Balance	2,672	(973)	1,058
Changes in AOCI
Balance	$ (272)	$ 2,672	$ (973)

RISK MANAGEMENT AND FINANCIAL_3

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - MARKET RISK (Details)	Dec. 31, 2019
Maximum
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Policy limit increase (percent)	30.00%
Interest Rate Swaption
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Average swap rate (as a percent)	2.90%
Interest rate contracts - long-term borrowings
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Average swap rate (as a percent)	3.00%

RISK MANAGEMENT AND FINANCIAL_4

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - TOTAL DERIVATIVE INSTRUMENTS (Details) - CAD ($)	Dec. 31, 2019	Dec. 31, 2018
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	$ (1,687,000,000)	$ (3,210,000,000)
Total Net Derivative Instruments	(1,687,000,000)	(3,210,000,000)
Derivative assets	327,000,000	498,000,000
Current derivative liabilities	920,000,000	1,234,000,000
Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(1,143,000,000)	(2,894,000,000)
Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(531,000,000)	(301,000,000)
Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(13,000,000)	(15,000,000)
Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	328,000,000	498,000,000
Derivative assets, Amounts Available for Offset	(125,000,000)	(153,000,000)
Derivative assets, Total Net Derivative Instruments	203,000,000	345,000,000
Derivative assets	327,000,000	498,000,000
Accounts receivable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	327,000,000	474,000,000
Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	1,000,000	24,000,000
Accounts receivable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	101,000,000	119,000,000
Derivative assets, Amounts Available for Offset	(44,000,000)	(60,000,000)
Derivative assets, Total Net Derivative Instruments	57,000,000	59,000,000
Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	89,000,000	72,000,000
Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	12,000,000	47,000,000
Deferred amounts and other assets | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(936,000,000)	(1,234,000,000)
Derivative liabilities, Amounts Available for Offset	125,000,000	153,000,000
Derivative liabilities, Total Net Derivative Instruments	(811,000,000)	(1,081,000,000)
Current derivative liabilities	920,000,000	1,234,000,000
Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(565,000,000)	(1,065,000,000)
Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(358,000,000)	(169,000,000)
Accounts payable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(13,000,000)	0
Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(1,180,000,000)	(2,593,000,000)
Derivative liabilities, Amounts Available for Offset	44,000,000	60,000,000
Derivative liabilities, Total Net Derivative Instruments	(1,136,000,000)	(2,533,000,000)
Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(994,000,000)	(2,375,000,000)
Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(186,000,000)	(203,000,000)
Other long-term liabilities | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	(15,000,000)
Accounts receivable from affiliates
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	1,000,000	0
Accounts payable to affiliates
TOTAL DERIVATIVE INSTRUMENTS
Current derivative liabilities	16,000,000	0
Forward currency contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(1,102,000,000)	(2,718,000,000)
Total Net Derivative Instruments	(1,102,000,000)	(2,718,000,000)
Forward currency contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(1,094,000,000)	(2,720,000,000)
Forward currency contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	5,000,000	17,000,000
Forward currency contracts | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(13,000,000)	(15,000,000)
Forward currency contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	161,000,000	47,000,000
Derivative assets, Amounts Available for Offset	(78,000,000)	(37,000,000)
Derivative assets, Total Net Derivative Instruments	83,000,000	10,000,000
Forward currency contracts | Accounts receivable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	161,000,000	47,000,000
Forward currency contracts | Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Forward currency contracts | Accounts receivable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Forward currency contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	81,000,000	62,000,000
Derivative assets, Amounts Available for Offset	(42,000,000)	(39,000,000)
Derivative assets, Total Net Derivative Instruments	39,000,000	23,000,000
Forward currency contracts | Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	71,000,000	39,000,000
Forward currency contracts | Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	10,000,000	23,000,000
Forward currency contracts | Deferred amounts and other assets | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Forward currency contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(410,000,000)	(615,000,000)
Derivative liabilities, Amounts Available for Offset	78,000,000	37,000,000
Derivative liabilities, Total Net Derivative Instruments	(332,000,000)	(578,000,000)
Forward currency contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(392,000,000)	(610,000,000)
Forward currency contracts | Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(5,000,000)	(5,000,000)
Forward currency contracts | Accounts payable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(13,000,000)	0
Forward currency contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(934,000,000)	(2,212,000,000)
Derivative liabilities, Amounts Available for Offset	42,000,000	39,000,000
Derivative liabilities, Total Net Derivative Instruments	(892,000,000)	(2,173,000,000)
Forward currency contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(934,000,000)	(2,196,000,000)
Forward currency contracts | Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	(1,000,000)
Forward currency contracts | Other long-term liabilities | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	(15,000,000)
Interest rate contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(534,000,000)	(515,000,000)
Total Net Derivative Instruments	(534,000,000)	(515,000,000)
Interest rate contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	0	(178,000,000)
Interest rate contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(534,000,000)	(337,000,000)
Interest rate contracts | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	0	0
Interest rate contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented		22,000,000
Derivative assets, Amounts Available for Offset		(2,000,000)
Derivative assets, Total Net Derivative Instruments		20,000,000
Interest rate contracts | Accounts receivable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented		0
Interest rate contracts | Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented		22,000,000
Interest rate contracts | Accounts receivable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented		0
Interest rate contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented		5,000,000
Derivative assets, Amounts Available for Offset		0
Derivative assets, Total Net Derivative Instruments		5,000,000
Interest rate contracts | Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented		0
Interest rate contracts | Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented		5,000,000
Interest rate contracts | Deferred amounts and other assets | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented		0
Interest rate contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(353,000,000)	(341,000,000)
Derivative liabilities, Amounts Available for Offset	0	2,000,000
Derivative liabilities, Total Net Derivative Instruments	(353,000,000)	(339,000,000)
Interest rate contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	(178,000,000)
Interest rate contracts | Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(353,000,000)	(163,000,000)
Interest rate contracts | Accounts payable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Interest rate contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(181,000,000)	(201,000,000)
Derivative liabilities, Amounts Available for Offset	0	0
Derivative liabilities, Total Net Derivative Instruments	(181,000,000)	(201,000,000)
Interest rate contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Interest rate contracts | Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(181,000,000)	(201,000,000)
Interest rate contracts | Other long-term liabilities | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Commodity contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(58,000,000)	30,000,000
Total Net Derivative Instruments	(58,000,000)	30,000,000
Commodity contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(53,000,000)	9,000,000
Commodity contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(5,000,000)	21,000,000
Commodity contracts | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	0	0
Commodity contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	163,000,000	429,000,000
Derivative assets, Amounts Available for Offset	(47,000,000)	(114,000,000)
Derivative assets, Total Net Derivative Instruments	116,000,000	315,000,000
Commodity contracts | Accounts receivable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	163,000,000	427,000,000
Commodity contracts | Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	2,000,000
Commodity contracts | Accounts receivable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Commodity contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	17,000,000	52,000,000
Derivative assets, Amounts Available for Offset	(2,000,000)	(21,000,000)
Derivative assets, Total Net Derivative Instruments	15,000,000	31,000,000
Commodity contracts | Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	17,000,000	33,000,000
Commodity contracts | Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	19,000,000
Commodity contracts | Deferred amounts and other assets | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Commodity contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(173,000,000)	(273,000,000)
Derivative liabilities, Amounts Available for Offset	47,000,000	114,000,000
Derivative liabilities, Total Net Derivative Instruments	(126,000,000)	(159,000,000)
Commodity contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(173,000,000)	(273,000,000)
Commodity contracts | Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Commodity contracts | Accounts payable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Commodity contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(65,000,000)	(178,000,000)
Derivative liabilities, Amounts Available for Offset	2,000,000	21,000,000
Derivative liabilities, Total Net Derivative Instruments	(63,000,000)	(157,000,000)
Commodity contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(60,000,000)	(178,000,000)
Commodity contracts | Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(5,000,000)	0
Commodity contracts | Other long-term liabilities | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Other contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	7,000,000	(7,000,000)
Total Net Derivative Instruments	7,000,000	(7,000,000)
Other contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	4,000,000	(5,000,000)
Other contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	3,000,000	(2,000,000)
Other contracts | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	0	0
Other contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	4,000,000
Derivative assets, Amounts Available for Offset	0
Derivative assets, Total Net Derivative Instruments	4,000,000
Other contracts | Accounts receivable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	3,000,000
Other contracts | Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	1,000,000
Other contracts | Accounts receivable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0
Other contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	3,000,000
Derivative assets, Amounts Available for Offset	0
Derivative assets, Total Net Derivative Instruments	3,000,000
Other contracts | Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	1,000,000
Other contracts | Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	2,000,000
Other contracts | Deferred amounts and other assets | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	$ 0
Other contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented		(5,000,000)
Derivative liabilities, Amounts Available for Offset		0
Derivative liabilities, Total Net Derivative Instruments		(5,000,000)
Other contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented		(4,000,000)
Other contracts | Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented		(1,000,000)
Other contracts | Accounts payable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented		0
Other contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented		(2,000,000)
Derivative liabilities, Amounts Available for Offset		0
Derivative liabilities, Total Net Derivative Instruments		(2,000,000)
Other contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented		(1,000,000)
Other contracts | Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented		(1,000,000)
Other contracts | Other long-term liabilities | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented		$ 0

RISK MANAGEMENT AND FINANCIAL_5

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - NOTIONAL PRINCIPAL OR QUANTITY INFORMATION (Details) € in Millions, ¥ in Millions, £ in Millions, MWh in Millions, MMBbls in Millions, Bcf in Millions, $ in Millions, $ in Millions	Dec. 31, 2019USD ($)MWhBcfMMBbls	Dec. 31, 2019CAD ($)MWhBcfMMBbls	Dec. 31, 2019EUR (€)MWhBcfMMBbls	Dec. 31, 2019JPY (¥)MWhBcfMMBbls	Dec. 31, 2019GBP (£)MWhBcfMMBbls	Dec. 31, 2018USD ($)MWhBcfMMBbls	Dec. 31, 2018CAD ($)MWhBcfMMBbls	Dec. 31, 2018EUR (€)MWhBcfMMBbls	Dec. 31, 2018JPY (¥)MWhBcfMMBbls	Dec. 31, 2018GBP (£)MWhBcfMMBbls
Foreign exchange contracts - United States dollar or GBP or Japanese yen forwards - purchase
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2020 notional principal	$ 1,121		€ 0	¥ 0
2021 notional principal	0		0	0
2022 notional principal	0		0	72,500
2023 notional principal	0		0	0
2024 notional principal	0		0	0
Thereafter notional principal	0		0	0
Total notional principal	1,121		0	¥ 72,500		$ 926		€ 226	¥ 52,662
Foreign exchange contracts - United States dollar or GBP forwards - sell
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2020 notional principal	5,631		23		£ 94
2021 notional principal	4,946		94		27
2022 notional principal	5,182		94		28
2023 notional principal	1,804		92		29
2024 notional principal	1,856		91		30
Thereafter notional principal	0		515		90
Total notional principal	$ 19,419		€ 909		£ 298	$ 19,075		€ 909		£ 318
Interest rate contracts - short-term borrowings
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2020 notional principal		$ 6,090
2021 notional principal		4,090
2022 notional principal		400
2023 notional principal		48
2024 notional principal		35
Thereafter notional principal		121
Total notional principal		10,784					$ 19,664
Interest rate contract - long term debt - Pay Fixed Rate
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2020 notional principal		3,533
2021 notional principal		1,569
2022 notional principal		0
2023 notional principal		0
2024 notional principal		0
Thereafter notional principal		0
Total notional principal		5,102					8,558
Equity contracts
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2020 notional principal		20
2021 notional principal		34
2022 notional principal		0
2023 notional principal		0
2024 notional principal		0
Thereafter notional principal		0
Total notional principal		$ 54					$ 55
Commodity contracts | Natural gas
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2020 notional quantity (in bcf, bbl or mbbl) | Bcf	(33)	(33)	(33)	(33)	(33)
2021 notional quantity (in bcf, bbl or mbbl) | Bcf	14	14	14	14	14
2022 notional quantity (in bcf, bbl or mbbl) | Bcf	15	15	15	15	15
2023 notional quantity (in bcf, bbl or mbbl) | Bcf	3	3	3	3	3
2024 notional quantity (in bcf, bbl or mbbl) | Bcf	0	0	0	0	0
Thereafter notional quantity (in bcf, bbl or mbbl) | Bcf	0	0	0	0	0
Total notional quantity (in bcf, bbl or mbbl) | Bcf	(1)	(1)	(1)	(1)	(1)	(167)	(167)	(167)	(167)	(167)
Commodity contracts | Crude oil
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2020 notional quantity (in bcf, bbl or mbbl) | MMBbls	28	28	28	28	28
2021 notional quantity (in bcf, bbl or mbbl) | MMBbls	0	0	0	0	0
2022 notional quantity (in bcf, bbl or mbbl) | MMBbls	0	0	0	0	0
2023 notional quantity (in bcf, bbl or mbbl) | MMBbls	0	0	0	0	0
2024 notional quantity (in bcf, bbl or mbbl) | MMBbls	0	0	0	0	0
Thereafter notional quantity (in bcf, bbl or mbbl) | MMBbls	0	0	0	0	0
Total notional quantity (in bcf, bbl or mbbl) | MMBbls	28	28	28	28	28	4	4	4	4	4
Commodity contracts | NGL
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2020 notional quantity (in bcf, bbl or mbbl) | MMBbls	2	2	2	2	2
2021 notional quantity (in bcf, bbl or mbbl) | MMBbls	0	0	0	0	0
2022 notional quantity (in bcf, bbl or mbbl) | MMBbls	0	0	0	0	0
2023 notional quantity (in bcf, bbl or mbbl) | MMBbls	0	0	0	0	0
2024 notional quantity (in bcf, bbl or mbbl) | MMBbls	0	0	0	0	0
Thereafter notional quantity (in bcf, bbl or mbbl) | MMBbls	0	0	0	0	0
Total notional quantity (in bcf, bbl or mbbl) | MMBbls	2	2	2	2	2	0	0	0	0	0
Commodity contracts | Power
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2020 notional quantity (MW/H) | MWh	80	80	80	80	80
2021 notional quantity (MW/H) | MWh	(3)	(3)	(3)	(3)	(3)
2022 notional quantity (MW/H) | MWh	(43)	(43)	(43)	(43)	(43)
2023 notional quantity (MW/H) | MWh	(43)	(43)	(43)	(43)	(43)
2024 notional quantity (MW/H) | MWh	(43)	(43)	(43)	(43)	(43)
Thereafter notional quantity (MW/H) | MWh	(43)	(43)	(43)	(43)	(43)
Total notional quantity (MW/H) | MWh	(16)	(16)	(16)	(16)	(16)	(7)	(7)	(7)	(7)	(7)

RISK MANAGEMENT AND FINANCIAL_6

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - EFFECTS ON EARNINGS AND COMPREHENSIVE INCOME (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	$ (591)
Amount of unrealized gains/(loss) recognized in OCI		$ (141)	$ 297
Amount (gain)/loss reclassified from AOCI to earnings	158
Amount of (gains)/loss reclassified from AOCI to earnings (effective portion)		191	279
Unrealized gain on derivative	1,751	(903)	1,242
Unrealized gain on derivative		7
Unrealized gain on hedged item		1
Realized loss on derivative		(8)
Realized loss on hedged item		(1)
Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Estimated loss of AOCI related to cash flow hedges reclassified to earnings in the next 12 months	$ 80
Period to hedge exposures to the variability of cash flows for all forecasted transactions	24 months
Forward currency contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount (gain)/loss reclassified from AOCI to earnings	$ 5
Forward currency contracts | Other income/(expense)
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of (gains)/loss reclassified from AOCI to earnings (effective portion)		5	(104)
Forward currency contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	(19)
Amount of unrealized gains/(loss) recognized in OCI		19	(5)
Forward currency contracts | Net Investment Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	2
Amount of unrealized gains/(loss) recognized in OCI		31	284
Interest rate contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount (gain)/loss reclassified from AOCI to earnings	157
Interest rate contracts | Interest expense
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of (gains)/loss reclassified from AOCI to earnings (effective portion)		184	384
Interest rate contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	(559)
Amount of unrealized gains/(loss) recognized in OCI		(190)	6
Commodity contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount (gain)/loss reclassified from AOCI to earnings	(1)
Commodity contracts | Commodity costs
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of (gains)/loss reclassified from AOCI to earnings (effective portion)		(1)	(9)
Commodity contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	(25)
Amount of unrealized gains/(loss) recognized in OCI		2	11
Other contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount (gain)/loss reclassified from AOCI to earnings	(3)
Other contracts | Operating and administrative expense
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of (gains)/loss reclassified from AOCI to earnings (effective portion)		3	8
Other contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	10
Amount of unrealized gains/(loss) recognized in OCI		(3)	1
Interest Rate Swap | Interest expense
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of (gains)/loss reclassified from AOCI to earnings (effective portion)			296
Non-Qualifying Derivative Instruments | Forward currency contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain on derivative	1,626	(1,390)	1,284
Non-Qualifying Derivative Instruments | Forward currency contracts | Transportation and other services revenues
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain on derivative	930	(1,108)	800
Non-Qualifying Derivative Instruments | Forward currency contracts | Other income/(expense)
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain on derivative	696	(282)	484
Non-Qualifying Derivative Instruments | Interest rate contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain on derivative	178	5	157
Non-Qualifying Derivative Instruments | Commodity contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain on derivative	(62)	485	(199)
Non-Qualifying Derivative Instruments | Commodity contracts | Transportation and other services revenues
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain on derivative	(26)	66	(104)
Non-Qualifying Derivative Instruments | Commodity contracts | Commodity sales
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain on derivative	(544)	599	90
Non-Qualifying Derivative Instruments | Commodity contracts | Commodity costs
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain on derivative	459	(193)	(223)
Non-Qualifying Derivative Instruments | Commodity contracts | Operating and administrative expense
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain on derivative	49	13	38
Non-Qualifying Derivative Instruments | Other contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain on derivative	$ 9	$ (3)	$ 0

RISK MANAGEMENT AND FINANCIAL_7

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - LIQUIDITY AND CREDIT RISK (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
LIQUIDITY RISK AND CREDIT RISK
Rolling time period over which the Company forecasts cash requirements	12 months
Period of anticipated requirements for which the Company maintains sufficient liquidity through committed credit facilities	1 year
Period after which receivables are classified as past due	30 days
Letters of credit provided in lieu of providing cash collateral to counterparties	$ 0
Cash collateral	0	$ 0
Derivative instruments
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	394,000,000	562,000,000
Derivative instruments | Canadian financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	146,000,000	28,000,000
Derivative instruments | United States financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	40,000,000	107,000,000
Derivative instruments | European financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	3,000,000	84,000,000
Derivative instruments | Asian financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	92,000,000	6,000,000
Derivative instruments | Other
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	$ 113,000,000	$ 337,000,000

RISK MANAGEMENT AND FINANCIAL_8

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - FAIR VALUE OF DERIVATIVES (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Fair Value of Derivatives
Short-term portion of derivative assets	$ 327	$ 498
Current derivative liabilities	(920)	(1,234)
Total net derivative asset/(liability)	(1,687)	(3,210)
Forward currency contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	(1,102)	(2,718)
Interest rate contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	(534)	(515)
Commodity contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	(58)	30
Other contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	7	(7)
Fair Value
Fair Value of Derivatives
Short-term portion of derivative assets	328	498
Long-term derivative assets	101	119
Current derivative liabilities	(936)	(1,234)
Long-term derivative liabilities	(1,180)	(2,593)
Total net derivative asset/(liability)	(1,687)	(3,210)
Fair Value | Forward currency contracts
Fair Value of Derivatives
Short-term portion of derivative assets	161	47
Long-term derivative assets	81	62
Current derivative liabilities	(410)	(615)
Long-term derivative liabilities	(934)	(2,212)
Total net derivative asset/(liability)	(1,102)	(2,718)
Fair Value | Interest rate contracts
Fair Value of Derivatives
Short-term portion of derivative assets		22
Long-term derivative assets		5
Current derivative liabilities	(353)	(341)
Long-term derivative liabilities	(181)	(201)
Total net derivative asset/(liability)	(534)	(515)
Fair Value | Commodity contracts
Fair Value of Derivatives
Short-term portion of derivative assets	163	429
Long-term derivative assets	17	52
Current derivative liabilities	(173)	(273)
Long-term derivative liabilities	(65)	(178)
Total net derivative asset/(liability)	(58)	30
Fair Value | Other contracts
Fair Value of Derivatives
Short-term portion of derivative assets	4
Long-term derivative assets	3
Current derivative liabilities	0	(5)
Long-term derivative liabilities	0	(2)
Total net derivative asset/(liability)		(7)
Level 1 | Fair Value
Fair Value of Derivatives
Short-term portion of derivative assets	0	24
Long-term derivative assets	0	0
Current derivative liabilities	(5)	(7)
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	(5)	17
Level 1 | Fair Value | Forward currency contracts
Fair Value of Derivatives
Short-term portion of derivative assets	0	0
Long-term derivative assets	0	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	0	0
Level 1 | Fair Value | Interest rate contracts
Fair Value of Derivatives
Short-term portion of derivative assets		0
Long-term derivative assets		0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	0	0
Level 1 | Fair Value | Commodity contracts
Fair Value of Derivatives
Short-term portion of derivative assets	0	24
Long-term derivative assets	0	0
Current derivative liabilities	(5)	(7)
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	(5)	17
Level 1 | Fair Value | Other contracts
Fair Value of Derivatives
Short-term portion of derivative assets	0
Long-term derivative assets	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	0	0
Level 2 | Fair Value
Fair Value of Derivatives
Short-term portion of derivative assets	198	114
Long-term derivative assets	96	97
Current derivative liabilities	(786)	(989)
Long-term derivative liabilities	(1,121)	(2,438)
Total net derivative asset/(liability)	(1,613)	(3,216)
Level 2 | Fair Value | Forward currency contracts
Fair Value of Derivatives
Short-term portion of derivative assets	161	47
Long-term derivative assets	81	62
Current derivative liabilities	(410)	(615)
Long-term derivative liabilities	(934)	(2,212)
Total net derivative asset/(liability)	(1,102)	(2,718)
Level 2 | Fair Value | Interest rate contracts
Fair Value of Derivatives
Short-term portion of derivative assets		22
Long-term derivative assets		5
Current derivative liabilities	(353)	(341)
Long-term derivative liabilities	(181)	(201)
Total net derivative asset/(liability)	(534)	(515)
Level 2 | Fair Value | Commodity contracts
Fair Value of Derivatives
Short-term portion of derivative assets	33	45
Long-term derivative assets	12	30
Current derivative liabilities	(23)	(28)
Long-term derivative liabilities	(6)	(23)
Total net derivative asset/(liability)	16	24
Level 2 | Fair Value | Other contracts
Fair Value of Derivatives
Short-term portion of derivative assets	4
Long-term derivative assets	3
Current derivative liabilities	0	(5)
Long-term derivative liabilities	0	(2)
Total net derivative asset/(liability)	7	(7)
Level 3 | Fair Value
Fair Value of Derivatives
Short-term portion of derivative assets	130	360
Long-term derivative assets	5	22
Current derivative liabilities	(145)	(238)
Long-term derivative liabilities	(59)	(155)
Total net derivative asset/(liability)	(69)	(11)
Level 3 | Fair Value | Forward currency contracts
Fair Value of Derivatives
Short-term portion of derivative assets	0	0
Long-term derivative assets	0	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	0	0
Level 3 | Fair Value | Interest rate contracts
Fair Value of Derivatives
Short-term portion of derivative assets		0
Long-term derivative assets		0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	0	0
Level 3 | Fair Value | Commodity contracts
Fair Value of Derivatives
Short-term portion of derivative assets	130	360
Long-term derivative assets	5	22
Current derivative liabilities	(145)	(238)
Long-term derivative liabilities	(59)	(155)
Total net derivative asset/(liability)	(69)	(11)
Level 3 | Fair Value | Other contracts
Fair Value of Derivatives
Short-term portion of derivative assets	0
Long-term derivative assets	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	$ 0	$ 0

RISK MANAGEMENT AND FINANCIAL_9

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - LEVEL 3 INPUTS (Details) $ in Millions	Dec. 31, 2019CAD ($)$ / bbl$ / MWh$ / MillionsofBTU-MMBTU$ / Gallon-gal	Dec. 31, 2018CAD ($)
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (1,687)	$ (3,210)
Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(1,687)	(3,210)
Level 3 | Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (69)	$ (11)
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Natural gas | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / MillionsofBTU-MMBTU	1.95
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Natural gas | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / MillionsofBTU-MMBTU	4.88
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Natural gas | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / MillionsofBTU-MMBTU	3.04
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Crude oil | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / bbl	44.24
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Crude oil | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / bbl	82.29
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Crude oil | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / bbl	52.76
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | NGL | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / Gallon-gal	0.54
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | NGL | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / Gallon-gal	0.86
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | NGL | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / Gallon-gal	0.82
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Power | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / MWh	27.84
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Power | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / MWh	71.79
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Power | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / MWh	57.46
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Natural gas | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / MillionsofBTU-MMBTU	1
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Natural gas | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / MillionsofBTU-MMBTU	8.37
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Natural gas | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / MillionsofBTU-MMBTU	2.53
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Crude oil | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / bbl	40.20
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Crude oil | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / bbl	90.75
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Crude oil | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / bbl	70.27
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | NGL | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / Gallon-gal	0.18
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | NGL | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / Gallon-gal	2.01
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | NGL | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / Gallon-gal	0.79
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Financial | Natural gas
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ 0
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Financial | Crude oil
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	4
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Financial | NGL
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	3
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Financial | Power
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(61)
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Physical | Natural gas
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	28
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Physical | Crude oil
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(45)
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Physical | NGL
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ 2

RISK MANAGEMENT AND FINANCIA_10

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - CHANGES IN LEVEL 3 (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Changes in net fair value of derivative assets and liabilities classified as Level 3
Level 3 net derivative asset at beginning of period	$ (11)	$ (387)
Total gains/(loss)
Included in earnings	27	206
Included in OCI	(25)	2
Settlements	(60)	168
Level 3 net derivative asset at end of period	(69)	(11)
Amount of transfer of fair value of assets between levels	0	0
Amount of transfer of fair value of liabilities between levels	$ 0	$ 0

RISK MANAGEMENT AND FINANCIA_11

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - OTHER FINANCIAL INSTRUMENTS (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value of Other Financial Instruments
Equity investments at carrying value	$ 99,000,000	$ 102,000,000
Restricted long-term investments	434,000,000	323,000,000
Long-term debt	70,500,000,000	64,400,000,000
Long-term loans receivable from affiliates	1,026,000,000	767,000,000
Net Investment Hedges
Fair Value of Other Financial Instruments
Unrealized foreign exchange gain (loss) on translation of United States dollar denominated debt	317,000,000	479,000,000
Unrealized gain (loss) on change in fair value of outstanding forward exchange forward contracts	2,000,000	30,000,000
Realized loss associated with the settlement of foreign exchange forward contracts	0	45,000,000
Realized gain (loss) associated with the settlement of United Stated dollar denominated debt that matured	0	14,000,000
Carrying value
Fair Value of Other Financial Instruments
Long-term debt	64,400,000,000	63,900,000,000
Preference shares
Fair Value of Other Financial Instruments
Held-to-maturity securities	$ 580,000,000	478,000,000
Cumulative dividends based on average yield of Government of Canada bonds, maturity period of bonds	10 years
Held to maturity preferred share investment	$ 580,000,000	$ 580,000,000
Noverco | Preference shares
Fair Value of Other Financial Instruments
Cumulative dividends based on average yield of Government of Canada bonds, spread over reference rate (as a percent)	4.38%

INCOME TAXES - RATE RECONCILIAT

INCOME TAXES - RATE RECONCILIATION (Details) - CAD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
INCOME TAX RATE RECONCILIATION
Earnings before income taxes			$ 7,535	$ 3,570	$ 569
Canadian federal statutory income tax rate			15.00%	15.00%	15.00%
Expected federal taxes at statutory rate			$ 1,130	$ 536	$ 85
Increase/(decrease) resulting from:
Provincial and state income taxes			415	(24)	133
Foreign and other statutory rate differentials			129	94	(601)
Impact of United States tax reform	$ (223)	$ (30)	0	(2)	(2,045)
Effects of rate-regulated accounting			(63)	(163)	(189)
Foreign allowable interest deductions			(29)	(134)	(124)
Part VI.1 tax, net of federal Part I deduction			78	76	68
Impairment of goodwill			0	192	15
United States BEAT tax			67	43	0
Non-taxable portion of gain on sale of investment to unrelated party			0	31	0
Valuation allowance			26	(172)	(17)
Intercorporate investments			(14)	(149)	77
Noncontrolling interests			(13)	(47)	(80)
Other			(18)	(44)	(19)
Income tax (recovery)/expense			$ 1,708	$ 237	$ (2,697)
Effective income tax rate (as a percent)			22.70%	6.60%	(474.00%)

INCOME TAXES - COMPONENTS (Deta

INCOME TAXES - COMPONENTS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings/(loss) before income taxes and discontinued operations
Earnings before income taxes	$ 7,535	$ 3,570	$ 569
Current income taxes
Total current income taxes	552	385	180
Deferred income taxes
Total deferred income taxes	1,156	(148)	(2,877)
Income tax (recovery)/expense	1,708	237	(2,697)
Canada
Earnings/(loss) before income taxes and discontinued operations
Domestic	3,560	118	2,200
Current income taxes
Domestic	347	311	129
Deferred income taxes
Domestic	490	(598)	299
United States
Earnings/(loss) before income taxes and discontinued operations
Foreign	3,115	2,582	(2,431)
Current income taxes
Foreign	107	66	46
Deferred income taxes
Foreign	672	439	(3,160)
Other
Earnings/(loss) before income taxes and discontinued operations
Foreign	860	870	800
Current income taxes
Foreign	98	8	5
Deferred income taxes
Foreign	$ (6)	$ 11	$ (16)

INCOME TAXES - DEFERRED INCOME

INCOME TAXES - DEFERRED INCOME TAXES (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Deferred income tax liabilities
Property, plant and equipment	$ (7,290)	$ (7,018)
Investments	(4,620)	(4,441)
Regulatory assets	(1,052)	(756)
Other	(40)	(192)
Total deferred income tax liabilities	(13,002)	(12,407)
Deferred income tax assets
Financial instruments	679	1,103
Pension and OPEB plans	206	181
Loss carryforwards	1,693	1,820
Other	1,641	1,274
Total deferred income tax assets	4,219	4,378
Less valuation allowance	(84)	(51)
Total deferred income tax assets, net	4,135	4,327
Net deferred income tax liabilities	(8,867)	(8,080)
Total deferred income tax assets	1,000	1,374
Total deferred income tax liabilities	(9,867)	(9,454)
Foreign subsidiaries' undistributed earnings on which deferred income taxes has not been provided	5,300	5,800
Canada
Deferred income tax assets
Benefit of unused tax loss carryforwards recognized	3,200	3,400
United States
Deferred income tax assets
Benefit of unused tax loss carryforwards recognized	$ 3,600	$ 3,400

INCOME TAXES - UNITED STATES TA

INCOME TAXES - UNITED STATES TAX REFROM (Details) - CAD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
United States BEAT tax			$ 67	$ 43	$ 0
Impact of United States tax reform	$ 223	$ 30	$ 0	$ 2	2,045
Provisional tax expense					34
Decrease in deferred income tax liability					3,100
Deferred income tax asset benefit					1,100
Reduction in tax amount					$ 200

INCOME TAXES - UNRECOGNIZED TAX

INCOME TAXES - UNRECOGNIZED TAX BENEFITS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
UNRECOGNIZED TAX BENEFITS
Unrecognized tax benefits at beginning of year	$ 139	$ 150
Gross increases for tax positions of current year	1	2
Gross decreases for tax positions of prior year	(1)	(12)
Change in translation of foreign currency	(4)	3
Lapses of statute of limitations	(6)	(3)
Settlements	0	(1)
Unrecognized tax benefits at end of year	129	139
Interest and penalties expense (recovery) related to unrecognized tax benefits	3	5
Accrued interest and penalties related to unrecognized tax benefits	$ 15	$ 12

PENSION AND OTHER POSTRETIREM_3

PENSION AND OTHER POSTRETIREMENT BENEFITS - BENEFIT OBLIGATION, PLAN ASSETS AND FUNDED STATUS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Canada
Change in plan assets
Employer contributions	$ 4	$ 13	$ 14
Canada | Pension
Change in projected benefit obligation
Accumulated postretirement benefit obligation at beginning of year	3,997	4,033
Service cost	149	149	156
Interest cost	139	130	116
Participant contributions	32	25
Actuarial (gain)/loss	423	(146)
Benefits paid	(187)	(184)
Plan settlements	(99)	0
Transfers out	(8)	(10)
Foreign currency exchange rate changes	0	0
Other	0	0
Accumulated postretirement benefit obligation at end of year	4,446	3,997	4,033
Change in plan assets
Fair value of plan assets at beginning of year	3,523	3,619
Actual return/(loss) on plan assets	448	(42)
Employer contributions	114	113
Participant contributions	32	25
Benefits paid	(187)	(184)
Plan settlements	(99)	0
Transfers out	(4)	(8)
Foreign currency exchange rate changes	0	0
Other	0	0
Fair value of plan assets at end of year	3,827	3,523	3,619
Underfunded status at end of year	(619)	(474)
Presented as follows:
Deferred amounts and other assets	35	29
Accounts payable and other	(9)	(9)
Other long-term liabilities	(645)	(494)
Amount recognized in balance sheet	(619)	(474)
Accumulated benefit obligation	4,000	3,700
Canada | Supplemental Employee Retirement Plan
Presented as follows:
Deferred amounts and other assets	10	7
Canada | OPEB
Change in projected benefit obligation
Accumulated postretirement benefit obligation at beginning of year	282	321
Service cost	5	8	7
Interest cost	10	10	10
Participant contributions	0	0
Actuarial (gain)/loss	15	(45)
Benefits paid	(6)	(11)
Plan settlements	0	0
Foreign currency exchange rate changes	0	0
Other	(13)	(1)
Accumulated postretirement benefit obligation at end of year	293	282	321
Change in plan assets
Fair value of plan assets at beginning of year	0	0
Actual return/(loss) on plan assets	0	0
Employer contributions	6	11
Participant contributions	0	0
Benefits paid	(6)	(11)
Foreign currency exchange rate changes	0	0
Other	0	0
Fair value of plan assets at end of year	0	0	0
Underfunded status at end of year	(293)	(282)
Presented as follows:
Deferred amounts and other assets	0	0
Accounts payable and other	(12)	(12)
Other long-term liabilities	(281)	(270)
Amount recognized in balance sheet	(293)	(282)
United States
Change in plan assets
Employer contributions	27	27	31
United States | Pension
Change in projected benefit obligation
Accumulated postretirement benefit obligation at beginning of year	1,214	1,279
Service cost	45	45	48
Interest cost	41	38	35
Participant contributions	0	0
Actuarial (gain)/loss	106	(103)
Benefits paid	(101)	(60)
Plan settlements	(1)	(65)
Transfers out	(6)	0
Foreign currency exchange rate changes	(63)	105
Other	(5)	(25)
Accumulated postretirement benefit obligation at end of year	1,230	1,214	1,279
Change in plan assets
Fair value of plan assets at beginning of year	1,045	1,097
Actual return/(loss) on plan assets	176	(48)
Employer contributions	46	40
Participant contributions	0	0
Benefits paid	(101)	(60)
Plan settlements	(1)	(65)
Transfers out	0	0
Foreign currency exchange rate changes	(56)	91
Other	(5)	(10)
Fair value of plan assets at end of year	1,104	1,045	1,097
Underfunded status at end of year	(126)	(169)
Presented as follows:
Deferred amounts and other assets	0	0
Accounts payable and other	(4)	(4)
Other long-term liabilities	(122)	(165)
Amount recognized in balance sheet	(126)	(169)
Accumulated benefit obligation	1,200	1,200
United States | Supplemental Employee Retirement Plan
Presented as follows:
Deferred amounts and other assets	51	39
United States | OPEB
Change in projected benefit obligation
Accumulated postretirement benefit obligation at beginning of year	305	337
Service cost	2	3	5
Interest cost	10	10	10
Participant contributions	5	6
Actuarial (gain)/loss	7	(25)
Benefits paid	(28)	(29)
Plan settlements	0	(8)
Foreign currency exchange rate changes	(15)	27
Other	2	(16)
Accumulated postretirement benefit obligation at end of year	288	305	337
Change in plan assets
Fair value of plan assets at beginning of year	181	213
Actual return/(loss) on plan assets	27	(13)
Employer contributions	10	8
Participant contributions	5	6
Benefits paid	(28)	(29)
Foreign currency exchange rate changes	(9)	16
Other	2	(20)
Fair value of plan assets at end of year	188	181	$ 213
Underfunded status at end of year	(100)	(124)
Presented as follows:
Deferred amounts and other assets	0	2
Accounts payable and other	(8)	(7)
Other long-term liabilities	(92)	(119)
Amount recognized in balance sheet	$ (100)	$ (124)

PENSION AND OTHER POSTRETIREM_4

PENSION AND OTHER POSTRETIREMENT BENEFITS PENSION AND OTHER POSTRETIREMENT BENEFITS - AMOUNT RECOGNIZED IN EXCESS OF ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Canada
Pension and Other Postretirement Benefit Disclosures
Projected benefit obligations	$ 1,481	$ 1,422
Accumulated benefit obligations	1,361	1,299
Fair value of plan assets	1,087	1,064
United States
Pension and Other Postretirement Benefit Disclosures
Projected benefit obligations	103	1,214
Accumulated benefit obligations	98	1,179
Fair value of plan assets	$ 0	$ 1,045

PENSION AND OTHER POSTRETIREM_5

PENSION AND OTHER POSTRETIREMENT BENEFITS - AMOUNT RECOGNIZED IN ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Canada | Pension
Amount included in AOCI
Net actuarial loss (gain)	$ 445	$ 435
Prior service credit	0	0
Total amount recognized in AOCI	445	435
Canada | OPEB
Amount included in AOCI
Net actuarial loss (gain)	(7)	(29)
Prior service credit	(1)	(2)
Total amount recognized in AOCI	(8)	(31)
United States | Pension
Amount included in AOCI
Net actuarial loss (gain)	134	133
Prior service credit	(2)	(3)
Total amount recognized in AOCI	132	130
United States | OPEB
Amount included in AOCI
Net actuarial loss (gain)	(23)	(15)
Prior service credit	(13)	(15)
Total amount recognized in AOCI	$ (36)	$ (30)

PENSION AND OTHER POSTRETIREM_6

PENSION AND OTHER POSTRETIREMENT BENEFITS - NET BENEFIT COSTS RECOGNIZED (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension | Canada
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	$ 149	$ 149	$ 156
Interest cost	139	130	116
Expected return on plan assets	(245)	(245)	(201)
Amortization/settlement of net actuarial loss	41	25	29
Amortization/curtailment of prior service (credit)/cost	0	0	0
Net periodic benefit cost	84	59	100
Defined contribution benefit cost	8	11	11
Net pension cost recognized in Earnings	92	70	111
Amount recognized in OCI:
Effect of plan combination	0	0	0
Amortization/settlement of net actuarial loss	(26)	(11)	(14)
Amortization/curtailment of prior service credit/(cost)	0	0	0
Net actuarial loss arising during the year	115	112	38
Total amount recognized in OCI	89	101	24
Total amount recognized in Comprehensive income	181	171	135
Expected amortization, next fiscal year	21
Pension | United States
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	45	45	48
Interest cost	41	38	35
Expected return on plan assets	(78)	(88)	(57)
Amortization/settlement of net actuarial loss	2	7	10
Amortization/curtailment of prior service (credit)/cost	(1)	3	0
Net periodic benefit cost	9	5	36
Defined contribution benefit cost	0	0	0
Net pension cost recognized in Earnings	9	5	36
Amount recognized in OCI:
Effect of plan combination	(6)	0	0
Amortization/settlement of net actuarial loss	(2)	(7)	(9)
Amortization/curtailment of prior service credit/(cost)	1	(3)	0
Net actuarial loss arising during the year	8	28	0
Total amount recognized in OCI	1	18	(9)
Total amount recognized in Comprehensive income	10	23	27
Expected amortization, next fiscal year	0
OPEB | Canada
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	5	8	7
Interest cost	10	10	10
Expected return on plan assets	0	0	0
Amortization/settlement of net actuarial loss	(7)	0	0
Amortization/curtailment of prior service (credit)/cost	(1)	0	1
Net pension cost recognized in Earnings	7	18	18
Amount recognized in OCI:
Amortization/settlement of net actuarial loss	7	0	(1)
Amortization/curtailment of prior service credit/(cost)	1	0	0
Net actuarial loss arising during the year	15	(46)	(8)
Prior service (credit)/cost	0	0	(3)
Total amount recognized in OCI	23	(46)	(12)
Total amount recognized in Comprehensive income	30	(28)	6
Expected amortization, next fiscal year	1
OPEB | United States
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	2	3	5
Interest cost	10	10	10
Expected return on plan assets	(12)	(12)	(10)
Amortization/settlement of net actuarial loss	0	(1)	0
Amortization/curtailment of prior service (credit)/cost	(2)	(4)	0
Net pension cost recognized in Earnings	(2)	(4)	5
Amount recognized in OCI:
Amortization/settlement of net actuarial loss	0	1	1
Amortization/curtailment of prior service credit/(cost)	2	4	0
Net actuarial loss arising during the year	(8)	(1)	(42)
Prior service (credit)/cost	0	(8)	1
Total amount recognized in OCI	(6)	(4)	(40)
Total amount recognized in Comprehensive income	(8)	$ (8)	$ (35)
Expected amortization, next fiscal year	$ 3

PENSION AND OTHER POSTRETIREM_7

PENSION AND OTHER POSTRETIREMENT BENEFITS - ACTUARIAL ASSUMPTIONS (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension | Canada
Projected benefit obligations (as percent)
Discount rate	3.00%	3.80%	3.60%
Rate of salary increase	3.20%	3.20%	3.20%
Net benefit cost (as percent)
Discount rate	3.80%	3.60%	4.00%
Expected rate of return on plan assets	7.00%	6.80%	6.50%
Rate of salary increase	3.20%	3.20%	3.70%
Pension | United States
Projected benefit obligations (as percent)
Discount rate	3.00%	3.90%	3.50%
Rate of salary increase	2.90%	2.80%	3.10%
Net benefit cost (as percent)
Discount rate	3.90%	3.40%	4.00%
Expected rate of return on plan assets	8.00%	7.40%	7.20%
Rate of salary increase	2.90%	2.90%	3.30%
OPEB | Canada
Projected benefit obligations (as percent)
Discount rate	3.10%	3.80%	3.60%
Net benefit cost (as percent)
Discount rate	3.80%	3.60%	4.00%
OPEB | United States
Projected benefit obligations (as percent)
Discount rate	2.80%	4.00%	3.50%
Net benefit cost (as percent)
Discount rate	4.00%	3.30%	4.00%
Expected rate of return on plan assets	6.70%	5.70%	6.00%

PENSION AND OTHER POSTRETIREM_8

PENSION AND OTHER POSTRETIREMENT BENEFITS - ASSUMED HEALTH CARE COST TREND RATES (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Canada
MEDICAL COST TRENDS (as percent)
Health care cost trend rate assumed for next year	4.00%	5.60%
Rate to which the cost trend is assumed to decline (ultimate trend rate)	4.00%	4.40%
Year that the rate reaches the ultimate trend rate		2034
Effect of 1% change in assumed medical care trend rate (as percent)
Increase in service and interest cost due to 1% increase in the assumed medical care trend rate	$ 1
Decrease in service and interest cost due to 1% decrease in the assumed medical care trend rate	(1)
Increase in benefit obligation due to 1% increase in the assumed medical care trend rate	21
Decrease in benefit obligation due to 1% decrease in the assumed medical care trend rate	$ (17)
United States
MEDICAL COST TRENDS (as percent)
Health care cost trend rate assumed for next year	7.20%	7.40%
Rate to which the cost trend is assumed to decline (ultimate trend rate)	4.50%	4.50%
Year that the rate reaches the ultimate trend rate	2037	2037
Effect of 1% change in assumed medical care trend rate (as percent)
Increase in service and interest cost due to 1% increase in the assumed medical care trend rate	$ 1
Decrease in service and interest cost due to 1% decrease in the assumed medical care trend rate	(1)
Increase in benefit obligation due to 1% increase in the assumed medical care trend rate	19
Decrease in benefit obligation due to 1% decrease in the assumed medical care trend rate	$ (17)

PENSION AND OTHER POSTRETIREM_9

PENSION AND OTHER POSTRETIREMENT BENEFITS - PLAN ASSETS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Canada | Equity securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	43.40%
Plan asset allocations	46.40%	45.80%
Canada | Fixed income securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	30.30%
Plan asset allocations	31.00%	38.80%
Canada | Alternatives
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	26.30%
Plan asset allocations	22.60%	15.40%
Canada | Pension
Change in plan assets
Fair value of plan assets at beginning of year	$ 3,523	$ 3,619
Fair value of plan assets at end of year	3,827	3,523
Canada | Pension | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	596
Fair value of plan assets at end of year	545	596
Canada | Pension | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	2,365
Fair value of plan assets at end of year	2,430	2,365
Canada | Pension | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	562	340
Unrealized and realized gains	10	77
Purchases and settlements, net	280	145
Fair value of plan assets at end of year	852	562
Canada | Pension | Cash and Cash Equivalents
Change in plan assets
Fair value of plan assets at beginning of year	240
Fair value of plan assets at end of year	184	240
Canada | Pension | Cash and Cash Equivalents | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	240
Fair value of plan assets at end of year	184	240
Canada | Pension | Cash and Cash Equivalents | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Cash and Cash Equivalents | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Equity Securities, Non-US
Change in plan assets
Fair value of plan assets at beginning of year	619
Fair value of plan assets at end of year	348	619
Canada | Pension | Equity Securities, Non-US | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	138
Fair value of plan assets at end of year	165	138
Canada | Pension | Equity Securities, Non-US | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	481
Fair value of plan assets at end of year	183	481
Canada | Pension | Equity Securities, Non-US | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Equity Securities, US
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Equity Securities, US | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Equity Securities, US | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Equity Securities, US | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Equity Securities, Global
Change in plan assets
Fair value of plan assets at beginning of year	992
Fair value of plan assets at end of year	1,429	992
Canada | Pension | Equity Securities, Global | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Equity Securities, Global | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	992
Fair value of plan assets at end of year	1,429	992
Canada | Pension | Equity Securities, Global | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Government
Change in plan assets
Fair value of plan assets at beginning of year	671
Fair value of plan assets at end of year	614	671
Canada | Pension | Government | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	218
Fair value of plan assets at end of year	196	218
Canada | Pension | Government | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	453
Fair value of plan assets at end of year	418	453
Canada | Pension | Government | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Corporate
Change in plan assets
Fair value of plan assets at beginning of year	457
Fair value of plan assets at end of year	388	457
Canada | Pension | Corporate | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Corporate | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	457
Fair value of plan assets at end of year	388	457
Canada | Pension | Corporate | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Infrastructure and real estate
Change in plan assets
Fair value of plan assets at beginning of year	562
Fair value of plan assets at end of year	852	562
Canada | Pension | Infrastructure and real estate | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Infrastructure and real estate | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Infrastructure and real estate | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	562
Fair value of plan assets at end of year	852	562
Canada | Pension | Forward currency contracts
Change in plan assets
Fair value of plan assets at beginning of year	(18)
Fair value of plan assets at end of year	12	(18)
Canada | Pension | Forward currency contracts | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Forward currency contracts | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	(18)
Fair value of plan assets at end of year	12	(18)
Canada | Pension | Forward currency contracts | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB
Change in plan assets
Fair value of plan assets at beginning of year	0	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0	0
Unrealized and realized gains	0	0
Purchases and settlements, net	0	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Cash and Cash Equivalents | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Cash and Cash Equivalents | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Cash and Cash Equivalents | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Cash and Cash Equivalents | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Equity Securities, US
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Equity Securities, US | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Equity Securities, US | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Equity Securities, US | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Equity Securities, Global
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Equity Securities, Global | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Equity Securities, Global | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Equity Securities, Global | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Government | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Government | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Government | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Government | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Corporate | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year		0
Canada | OPEB | Corporate | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year		0
Canada | OPEB | Corporate | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year		0
Canada | OPEB | Corporate | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year		0
Canada | OPEB | Infrastructure and real estate | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Infrastructure and real estate | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Infrastructure and real estate | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Infrastructure and real estate | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	$ 0	$ 0
United States | Equity securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	45.00%
Plan asset allocations	55.20%	52.70%
United States | Fixed income securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	20.00%
Plan asset allocations	19.80%	34.90%
United States | Alternatives
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	35.00%
Plan asset allocations	25.00%	12.40%
United States | Pension
Change in plan assets
Fair value of plan assets at beginning of year	$ 1,045	$ 1,097
Fair value of plan assets at end of year	1,104	1,045
United States | Pension | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	56
Fair value of plan assets at end of year	14	56
United States | Pension | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	859
Fair value of plan assets at end of year	814	859
United States | Pension | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	130	56
Unrealized and realized gains	13	9
Purchases and settlements, net	133	65
Fair value of plan assets at end of year	276	130
United States | Pension | Cash and Cash Equivalents
Change in plan assets
Fair value of plan assets at beginning of year	56
Fair value of plan assets at end of year	14	56
United States | Pension | Cash and Cash Equivalents | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	56
Fair value of plan assets at end of year	14	56
United States | Pension | Cash and Cash Equivalents | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Cash and Cash Equivalents | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, Non-US
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, Non-US | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, Non-US | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, Non-US | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, US
Change in plan assets
Fair value of plan assets at beginning of year	110
Fair value of plan assets at end of year	93	110
United States | Pension | Equity Securities, US | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, US | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	110
Fair value of plan assets at end of year	93	110
United States | Pension | Equity Securities, US | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, Global
Change in plan assets
Fair value of plan assets at beginning of year	440
Fair value of plan assets at end of year	516	440
United States | Pension | Equity Securities, Global | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, Global | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	440
Fair value of plan assets at end of year	516	440
United States | Pension | Equity Securities, Global | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Government
Change in plan assets
Fair value of plan assets at beginning of year	265
Fair value of plan assets at end of year	164	265
United States | Pension | Government | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Government | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	265
Fair value of plan assets at end of year	164	265
United States | Pension | Government | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Corporate
Change in plan assets
Fair value of plan assets at beginning of year	44
Fair value of plan assets at end of year	41	44
United States | Pension | Corporate | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Corporate | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	44
Fair value of plan assets at end of year	41	44
United States | Pension | Corporate | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Infrastructure and real estate
Change in plan assets
Fair value of plan assets at beginning of year	130
Fair value of plan assets at end of year	276	130
United States | Pension | Infrastructure and real estate | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Infrastructure and real estate | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Infrastructure and real estate | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	130
Fair value of plan assets at end of year	276	130
United States | Pension | Forward currency contracts
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Forward currency contracts | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Forward currency contracts | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Forward currency contracts | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB
Change in plan assets
Fair value of plan assets at beginning of year	181	213
Fair value of plan assets at end of year	188	181
United States | OPEB | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	181
Fair value of plan assets at end of year	188	181
United States | OPEB | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	50
Fair value of plan assets at end of year	42	50
United States | OPEB | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	126
Fair value of plan assets at end of year	128	126
United States | OPEB | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	5	0
Unrealized and realized gains	1	0
Purchases and settlements, net	12	5
Fair value of plan assets at end of year	18	5
United States | OPEB | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	5
Fair value of plan assets at end of year	18	5
United States | OPEB | Cash and Cash Equivalents | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	7
Fair value of plan assets at end of year	2	7
United States | OPEB | Cash and Cash Equivalents | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	7
Fair value of plan assets at end of year	2	7
United States | OPEB | Cash and Cash Equivalents | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Cash and Cash Equivalents | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Equity Securities, US
Change in plan assets
Fair value of plan assets at beginning of year	68
Fair value of plan assets at end of year	75	68
United States | OPEB | Equity Securities, US | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Equity Securities, US | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	68
Fair value of plan assets at end of year	75	68
United States | OPEB | Equity Securities, US | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Equity Securities, Global
Change in plan assets
Fair value of plan assets at beginning of year	30
Fair value of plan assets at end of year	38	30
United States | OPEB | Equity Securities, Global | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Equity Securities, Global | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	30
Fair value of plan assets at end of year	38	30
United States | OPEB | Equity Securities, Global | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Government | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	71
Fair value of plan assets at end of year	55	71
United States | OPEB | Government | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	43
Fair value of plan assets at end of year	40	43
United States | OPEB | Government | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	28
Fair value of plan assets at end of year	15	28
United States | OPEB | Government | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Corporate | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year		0
United States | OPEB | Corporate | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year		0
United States | OPEB | Corporate | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year		0
United States | OPEB | Corporate | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year		0
United States | OPEB | Infrastructure and real estate | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	5
Fair value of plan assets at end of year	18	5
United States | OPEB | Infrastructure and real estate | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Infrastructure and real estate | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Infrastructure and real estate | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	5
Fair value of plan assets at end of year	$ 18	$ 5

PENSION AND OTHER POSTRETIRE_10

PENSION AND OTHER POSTRETIREMENT BENEFITS - EXPECTED BENEFIT PAYMENTS AND EMPLOYER CONTRIBUTIONS (Details) $ in Millions	Dec. 31, 2019CAD ($)
Canada | Pension
Benefits Expected to be Paid by the Company
Expected future benefit payments for 2020	$ 180
Expected future benefit payments for 2021	186
Expected future benefit payments for 2022	192
Expected future benefit payments for 2023	198
Expected future benefit payments for 2024	204
Expected future benefit payments for 2025-2029	1,105
Contributions expected to be paid in next fiscal year	104
Canada | OPEB
Benefits Expected to be Paid by the Company
Expected future benefit payments for 2020	12
Expected future benefit payments for 2021	12
Expected future benefit payments for 2022	12
Expected future benefit payments for 2023	13
Expected future benefit payments for 2024	13
Expected future benefit payments for 2025-2029	69
Contributions expected to be paid in next fiscal year	12
United States | Pension
Benefits Expected to be Paid by the Company
Expected future benefit payments for 2020	87
Expected future benefit payments for 2021	90
Expected future benefit payments for 2022	91
Expected future benefit payments for 2023	89
Expected future benefit payments for 2024	91
Expected future benefit payments for 2025-2029	402
Contributions expected to be paid in next fiscal year	31
United States | OPEB
Benefits Expected to be Paid by the Company
Expected future benefit payments for 2020	23
Expected future benefit payments for 2021	22
Expected future benefit payments for 2022	21
Expected future benefit payments for 2023	20
Expected future benefit payments for 2024	19
Expected future benefit payments for 2025-2029	82
Contributions expected to be paid in next fiscal year	$ 8

PENSION AND OTHER POSTRETIRE_11

PENSION AND OTHER POSTRETIREMENT BENEFITS - RETIREMENT SAVINGS PLAN (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Canada
Pension and Other Postretirement Benefit Disclosures
Percent of match (percent)	2.50%
Total contributions by the Company	$ 4	$ 13	$ 14
United States
Pension and Other Postretirement Benefit Disclosures
Percent of match (percent)	6.00%
Total contributions by the Company	$ 27	$ 27	$ 31

LEASES - NARRATIVE (Details)

LEASES - NARRATIVE (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)
Lessee, Lease, Description [Line Items]
Operating lease, expense	$ 113
Operating lease, payments	$ 123
Minimum
Lessee, Lease, Description [Line Items]
Lessee, operating lease, remaining lease term	3 months
Lessor, operating lease, remaining lease term	2 months
Maximum
Lessee, Lease, Description [Line Items]
Lessee, operating lease, remaining lease term	28 years
Lessor, operating lease, remaining lease term	24 years

LEASES - SUPPLEMENTAL STATEMENT

LEASES - SUPPLEMENTAL STATEMENTS OF FINANCIAL POSITION (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Jan. 01, 2019
Leases [Abstract]
Operating lease right-of-use assets, net	$ 713	$ 771
Operating lease liabilities - current	94	86
Operating lease liabilities - long-term	689	770
Total operating lease liabilities	$ 783	$ 856
Weighted average remaining lease term	13 years	14 years
Weighted average discount rate (percent)	4.30%	4.32%

LEASES - OPERATING LEASE COMMIT

LEASES - OPERATING LEASE COMMITMENTS (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Jan. 01, 2019
Leases [Abstract]
2020	$ 128
2021	99
2022	94
2023	84
2024	79
Thereafter	588
Total undiscounted lease payments	1,072
Less imputed interest	(289)
Total operating lease liabilities	$ 783	$ 856

LEASES - LESSOR LEASE COMMITMEN

LEASES - LESSOR LEASE COMMITMENTS (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)
Leases [Abstract]
Operating lease income	$ 265
Variable lease income	360
Total lease income	$ 625

LEASES - LESSOR FUTURE EXPECTED

LEASES - LESSOR FUTURE EXPECTED LEASE PAYMENTS (Details) $ in Millions	Dec. 31, 2019CAD ($)
Leases [Abstract]
2020	$ 236
2021	199
2022	188
2023	180
2024	178
Thereafter	2,276
Future lease payments	$ 3,257

CHANGES IN OPERATING ASSETS A_3

CHANGES IN OPERATING ASSETS AND LIABILITIES (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CHANGES IN OPERATING ASSETS AND LIABILITIES
Accounts receivable and other	$ (659)	$ 857	$ (783)
Accounts receivable from affiliates	6	54	24
Inventory	(24)	164	(289)
Deferred amounts and other assets	133	226	(138)
Accounts payable and other	175	(151)	277
Accounts payable to affiliates	(24)	(122)	(62)
Interest payable	(41)	25	124
Other long-term liabilities	175	(138)	509
Changes in operating assets and liabilities	$ (259)	$ 915	$ (338)

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2017CAD ($)
RELATED PARTY TRANSACTIONS
Amounts charged to the Company for transportation services		$ 812		$ 572		$ 721
Purchase of natural gas by wholly owned subsidiaries		392		322		142
Sale of natural gas by wholly owned subsidiaries		145		122		60
Total revenue from contracts with customers		$ 19,697		20,797
Minimum
RELATED PARTY TRANSACTIONS
Annual interest rate on the loans (as a percent)	3.00%	3.00%
Maximum
RELATED PARTY TRANSACTIONS
Annual interest rate on the loans (as a percent)	8.00%	8.00%
Vector Pipeline joint venture
RELATED PARTY TRANSACTIONS
Revenue from related parties		$ 7		7		14
Spectra Energy Corp | Reimbursed Maintenance Expenses
RELATED PARTY TRANSACTIONS
Revenue from related parties	$ 36	48	$ 22	28	$ 8	10
Other affiliates
RELATED PARTY TRANSACTIONS
Amounts receivable from affiliates		1,023		769
Natural Gas, Midstream | DCP Midstream, LLC
RELATED PARTY TRANSACTIONS
Total revenue from contracts with customers	26	34	40	52	36	47
Natural Gas, Storage | DCP Midstream, LLC
RELATED PARTY TRANSACTIONS
Total revenue from contracts with customers	$ 52	$ 69	$ 11	$ 14	$ 3	$ 4

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - COMMITMENTS (Details) $ in Millions	Dec. 31, 2019CAD ($)
Annual debt maturities
Total	$ 63,585
Less than 1 year	4,394
2 years	6,856
3 years	4,054
4 years	2,585
5 years	7,712
Thereafter	37,984
Interest obligations
Total	29,498
Less than 1 year	2,416
2 years	2,296
3 years	2,216
4 years	2,076
5 years	1,915
Thereafter	18,579
Purchase of services, pipe and other materials, including transportation
Total	9,448
Less than 1 year	2,891
2 years	1,507
3 years	1,217
4 years	564
5 years	570
Thereafter	2,699
Maintenance agreements
Total	435
Less than 1 year	56
2 years	55
3 years	53
4 years	25
5 years	20
Thereafter	226
Land lease commitments
Total	1,190
Less than 1 year	30
2 years	35
3 years	35
4 years	35
5 years	36
Thereafter	1,019
Total
Total	104,156
Less than 1 year	9,787
2 years	10,749
3 years	7,575
4 years	5,285
5 years	10,253
Thereafter	$ 60,507

CONDENSED CONSOLIDATING FINAN_3

CONDENSED CONSOLIDATING FINANCIAL INFORMATION - Schedule of Long Term Debt Instruments (Details) $ in Millions, $ in Billions	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)
Condensed Financial Statements, Captions [Line Items]
Long-term debt		$ 63,585
Senior notes
Condensed Financial Statements, Captions [Line Items]
Long-term debt	$ 7.9	$ 7,600
2.900% Senior Notes due 2022 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	290.00%	290.00%
4.000% Senior Notes due 2023 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	400.00%	400.00%
2.500% Senior Notes due 2025 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	350.00%	350.00%
2.500% Senior Notes due 2025 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	250.00%	250.00%
4.250% Senior Notes due 2026 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	425.00%	425.00%
3.700% Senior Notes due 2027 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	370.00%	370.00%
3.125% Senior Notes due 2029 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	312.50%	312.50%
4.500% Senior Notes due 2044 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	450.00%	450.00%
5.500% Senior Notes due 2046 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	550.00%	550.00%
4.000% Senior Notes due 2049 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	400.00%	400.00%
4.530% Senior Notes due 2020 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	453.00%	453.00%
4.850% Senior Notes due 2020 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	485.00%	485.00%
4.260% Senior Notes due 2021 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	426.00%	426.00%
3.160% Senior Notes due 2021 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	316.00%	316.00%
4.850% Senior Notes due 2022 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	485.00%	485.00%
3.190% Senior Notes due 2022 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	319.00%	319.00%
3.940% Senior Notes due 2023 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	394.00%	394.00%
3.940% Senior Notes due 2023 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	394.00%	394.00%
3.950% Senior Notes due 2024 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	395.00%	395.00%
3.200% Senior Notes due 2027 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	320.00%	320.00%
6.100% Senior Notes due 2028 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	610.00%	610.00%
2.990% Senior Notes due 2029 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	299.00%	299.00%
7.220% Senior Notes due 2030 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	722.00%	722.00%
7.200% Senior Notes due 2032 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	720.00%	720.00%
5.570% Senior Notes due 2035 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	557.00%	557.00%
5.120% Senior Notes due 2040 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	575.00%	575.00%
5.120% Senior Notes due 2040 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	512.00%	512.00%
4.240% Senior Notes due 2042 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	424.00%	424.00%
4.570% Senior Notes due 2044 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	457.00%	457.00%
4.870% Senior Notes due 2044 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	487.00%	487.00%
4.560% Senior Notes due 2064 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	456.00%	456.00%
Spectra Energy Partners, LP | Senior notes
Condensed Financial Statements, Captions [Line Items]
Long-term debt	$ 3.9
Spectra Energy Partners, LP | 4.600% Senior Notes due 2021 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	4.60%	4.60%
Spectra Energy Partners, LP | 4.750% Senior Notes due 2024 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	4.75%	4.75%
Spectra Energy Partners, LP | 3.500% Senior Notes due 2025 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	3.50%	3.50%
Spectra Energy Partners, LP | 3.375% Senior Notes due 2026 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	3.375%	3.375%
Spectra Energy Partners, LP | 5.950% Senior Notes due 2043 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	5.95%	5.95%
Spectra Energy Partners, LP | 4.500% Senior Notes due 2045 | Senior notes
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	4.50%	4.50%
Enbridge Energy Partners, L.P. | Senior notes
Condensed Financial Statements, Captions [Line Items]
Long-term debt	$ 3
Enbridge Energy Partners, L.P. | 4.200% Notes due 2021
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	4.20%	4.20%
Enbridge Energy Partners, L.P. | 5.875% Notes due 2025
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	5.875%	5.875%
Enbridge Energy Partners, L.P. | 5.950% Notes due 2033
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	5.95%	5.95%
Enbridge Energy Partners, L.P. | 6.300% Notes due 2034
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	6.30%	6.30%
Enbridge Energy Partners, L.P. | 7.500% Notes due 2038
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	7.50%	7.50%
Enbridge Energy Partners, L.P. | 5.500% Notes due 2040
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	5.50%	5.50%
Enbridge Energy Partners, L.P. | 7.375% Notes due 2045
Condensed Financial Statements, Captions [Line Items]
Interest rate (percent)	7.375%	7.375%

CONDENSED CONSOLIDATING FINAN_4

CONDENSED CONSOLIDATING FINANCIAL INFORMATION - Condensed Consolidating Statements of Earnings and Comprehensive Income (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Statement of Income Captions [Line Items]
Total operating revenues	$ 12,352	$ 11,598	$ 13,263	$ 12,856	$ 11,562	$ 11,345	$ 10,745	$ 12,726	$ 50,069	$ 46,378	$ 44,378
Operating and administrative									6,991	6,792	6,442
Depreciation and amortization									3,391	3,246	3,163
Impairment of long-lived assets (Note 8 and Note 11)									423	1,104	4,463
Impairment of goodwill (Note 8 and Note 16)									0	1,019	102
Total operating expenses									41,809	41,562	42,807
Operating income	1,768	1,588	2,285	2,619	1,513	854	1,571	878	8,260	4,816	1,571
Income from equity investments (Note 13)									1,503	1,509	1,102
Equity earnings from consolidated subsidiaries									0	0	0
Net foreign currency gain/(loss)									477	(522)	237
Gain/(loss) on dispositions									(300)	(46)	16
Other, including other income/(expense) from affiliates									258	516	199
Interest expense									(2,663)	(2,703)	(2,556)
Earnings before income taxes									7,535	3,570	569
Income tax recovery/(expense) (Note 25)									(1,708)	(237)	2,697
Earnings	914	1,060	1,830	2,023	1,283	213	1,327	510	5,827	3,333	3,266
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests									(122)	(451)	(407)
Earnings attributable to controlling interests	842	1,045	1,832	1,986	1,184	4	1,160	534	5,705	2,882	2,859
Preference share dividends									(383)	(367)	(330)
Earnings attributable to common shareholders	$ 746	$ 949	$ 1,736	$ 1,891	$ 1,089	$ (90)	$ 1,071	$ 445	5,322	2,515	2,529
Earnings									5,827	3,333	3,266
Other comprehensive income/(loss), net of tax									(3,107)	4,138	(2,278)
Comprehensive income									2,720	7,471	988
Comprehensive income attributable to noncontrolling interests and redeemable noncontrolling interests									(7)	(801)	(160)
Comprehensive income attributable to controlling interests									2,713	6,670	828
Eliminations and Other
Condensed Statement of Income Captions [Line Items]
Total operating revenues									0	0	0
Operating and administrative									0	(78)	0
Depreciation and amortization									0	0	0
Impairment of long-lived assets (Note 8 and Note 11)									0	0	0
Impairment of goodwill (Note 8 and Note 16)									0	0	0
Total operating expenses									0	(78)	0
Operating income									0	78	0
Income from equity investments (Note 13)									(66)	(295)	(468)
Equity earnings from consolidated subsidiaries									(7,809)	(825)	(4,689)
Net foreign currency gain/(loss)									(1,088)	219	(241)
Gain/(loss) on dispositions									0	0	0
Other, including other income/(expense) from affiliates									(2,450)	(908)	(896)
Interest expense									2,492	925	925
Earnings before income taxes									(8,921)	(806)	(5,369)
Income tax recovery/(expense) (Note 25)									618	4,148	43
Earnings									(8,303)	3,342	(5,326)
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests									(122)	(451)	(407)
Earnings attributable to controlling interests									(8,425)	2,891	(5,733)
Preference share dividends									0	0	0
Earnings attributable to common shareholders									(8,425)	2,891	(5,733)
Earnings									(8,303)	3,342	(5,326)
Other comprehensive income/(loss), net of tax									830	(225)	(51)
Comprehensive income									(7,473)	3,117	(5,377)
Comprehensive income attributable to noncontrolling interests and redeemable noncontrolling interests									(7)	(801)	(160)
Comprehensive income attributable to controlling interests									(7,480)	2,316	(5,537)
Parent Issuer and Guarantor | Parent and Subsidiaries
Condensed Statement of Income Captions [Line Items]
Total operating revenues									0	0	0
Operating and administrative									128	180	169
Depreciation and amortization									67	59	56
Impairment of long-lived assets (Note 8 and Note 11)									0	0	0
Impairment of goodwill (Note 8 and Note 16)									0	0	0
Total operating expenses									195	239	225
Operating income									(195)	(239)	(225)
Income from equity investments (Note 13)									70	302	471
Equity earnings from consolidated subsidiaries									3,881	3,119	2,130
Net foreign currency gain/(loss)									1,671	(829)	500
Gain/(loss) on dispositions									(7)	360	(11)
Other, including other income/(expense) from affiliates									1,944	945	871
Interest expense									(1,268)	(1,080)	(816)
Earnings before income taxes									6,096	2,578	2,920
Income tax recovery/(expense) (Note 25)									(391)	304	(61)
Earnings									5,705	2,882	2,859
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests									0	0	0
Earnings attributable to controlling interests									5,705	2,882	2,859
Preference share dividends									(383)	(367)	(330)
Earnings attributable to common shareholders									5,322	2,515	2,529
Earnings									5,705	2,882	2,859
Other comprehensive income/(loss), net of tax									(2,992)	3,788	(2,031)
Comprehensive income									2,713	6,670	828
Comprehensive income attributable to noncontrolling interests and redeemable noncontrolling interests									0	0	0
Comprehensive income attributable to controlling interests									2,713	6,670	828
Subsidiary Non-Guarantors | Parent and Subsidiaries
Condensed Statement of Income Captions [Line Items]
Total operating revenues									50,069	46,378	44,378
Operating and administrative									6,874	6,622	6,111
Depreciation and amortization									3,324	3,187	3,107
Impairment of long-lived assets (Note 8 and Note 11)									423	1,104	4,463
Impairment of goodwill (Note 8 and Note 16)									0	1,019	102
Total operating expenses									41,625	41,333	42,420
Operating income									8,444	5,045	1,958
Income from equity investments (Note 13)									1,366	1,360	981
Equity earnings from consolidated subsidiaries									1,696	(1,581)	881
Net foreign currency gain/(loss)									(106)	80	(22)
Gain/(loss) on dispositions									(293)	(406)	27
Other, including other income/(expense) from affiliates									573	254	74
Interest expense									(2,966)	(1,689)	(1,753)
Earnings before income taxes									8,714	3,063	2,146
Income tax recovery/(expense) (Note 25)									(1,985)	(4,373)	2,706
Earnings									6,729	(1,310)	4,852
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests									0	0	0
Earnings attributable to controlling interests									6,729	(1,310)	4,852
Preference share dividends									0	0	0
Earnings attributable to common shareholders									6,729	(1,310)	4,852
Earnings									6,729	(1,310)	4,852
Other comprehensive income/(loss), net of tax									(929)	556	(412)
Comprehensive income									5,800	(754)	4,440
Comprehensive income attributable to noncontrolling interests and redeemable noncontrolling interests									0	0	0
Comprehensive income attributable to controlling interests									5,800	(754)	4,440
Spectra Energy Partners, LP | Subsidiary Issuer and Guarantor | Parent and Subsidiaries
Condensed Statement of Income Captions [Line Items]
Total operating revenues									0	0	0
Operating and administrative									5	14	146
Depreciation and amortization									0	0	0
Impairment of long-lived assets (Note 8 and Note 11)									0	0	0
Impairment of goodwill (Note 8 and Note 16)									0	0	0
Total operating expenses									5	14	146
Operating income									(5)	(14)	(146)
Income from equity investments (Note 13)									133	142	118
Equity earnings from consolidated subsidiaries									1,189	(1,634)	752
Net foreign currency gain/(loss)									0	8	0
Gain/(loss) on dispositions									0	0	0
Other, including other income/(expense) from affiliates									2	72	11
Interest expense									(330)	(302)	(221)
Earnings before income taxes									989	(1,728)	514
Income tax recovery/(expense) (Note 25)									44	(319)	0
Earnings									1,033	(2,047)	514
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests									0	0	0
Earnings attributable to controlling interests									1,033	(2,047)	514
Preference share dividends									0	0	0
Earnings attributable to common shareholders									1,033	(2,047)	514
Earnings									1,033	(2,047)	514
Other comprehensive income/(loss), net of tax									(67)	(9)	12
Comprehensive income									966	(2,056)	526
Comprehensive income attributable to noncontrolling interests and redeemable noncontrolling interests									0	0	0
Comprehensive income attributable to controlling interests									966	(2,056)	526
Enbridge Energy Partners, L.P. | Subsidiary Issuer and Guarantor | Parent and Subsidiaries
Condensed Statement of Income Captions [Line Items]
Total operating revenues									0	0	0
Operating and administrative									(16)	54	16
Depreciation and amortization									0	0	0
Impairment of long-lived assets (Note 8 and Note 11)									0	0	0
Impairment of goodwill (Note 8 and Note 16)									0	0	0
Total operating expenses									(16)	54	16
Operating income									16	(54)	(16)
Income from equity investments (Note 13)									0	0	0
Equity earnings from consolidated subsidiaries									1,043	921	926
Net foreign currency gain/(loss)									0	0	0
Gain/(loss) on dispositions									0	0	0
Other, including other income/(expense) from affiliates									189	153	139
Interest expense									(591)	(557)	(691)
Earnings before income taxes									657	463	358
Income tax recovery/(expense) (Note 25)									6	3	9
Earnings									663	466	367
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests									0	0	0
Earnings attributable to controlling interests									663	466	367
Preference share dividends									0	0	0
Earnings attributable to common shareholders									663	466	367
Earnings									663	466	367
Other comprehensive income/(loss), net of tax									51	28	204
Comprehensive income									714	494	571
Comprehensive income attributable to noncontrolling interests and redeemable noncontrolling interests									0	0	0
Comprehensive income attributable to controlling interests									714	494	571
Commodity sales
Condensed Statement of Income Captions [Line Items]
Total operating revenues									29,309	27,660	26,286
Cost of goods and services sold									28,802	26,818	26,065
Commodity sales | Eliminations and Other
Condensed Statement of Income Captions [Line Items]
Total operating revenues									0	0	0
Cost of goods and services sold									0	0	0
Commodity sales | Parent Issuer and Guarantor | Parent and Subsidiaries
Condensed Statement of Income Captions [Line Items]
Total operating revenues									0	0	0
Cost of goods and services sold									0	0	0
Commodity sales | Subsidiary Non-Guarantors | Parent and Subsidiaries
Condensed Statement of Income Captions [Line Items]
Total operating revenues									29,309	27,660	26,286
Cost of goods and services sold									28,802	26,818	26,065
Commodity sales | Spectra Energy Partners, LP | Subsidiary Issuer and Guarantor | Parent and Subsidiaries
Condensed Statement of Income Captions [Line Items]
Total operating revenues									0	0	0
Cost of goods and services sold									0	0	0
Commodity sales | Enbridge Energy Partners, L.P. | Subsidiary Issuer and Guarantor | Parent and Subsidiaries
Condensed Statement of Income Captions [Line Items]
Total operating revenues									0	0	0
Cost of goods and services sold									0	0	0
Gas distribution revenue
Condensed Statement of Income Captions [Line Items]
Total operating revenues									4,205	4,360	4,215
Cost of goods and services sold									2,202	2,583	2,572
Gas distribution revenue | Eliminations and Other
Condensed Statement of Income Captions [Line Items]
Total operating revenues									0	0	0
Cost of goods and services sold									0	0	0
Gas distribution revenue | Parent Issuer and Guarantor | Parent and Subsidiaries
Condensed Statement of Income Captions [Line Items]
Total operating revenues									0	0	0
Cost of goods and services sold									0	0	0
Gas distribution revenue | Subsidiary Non-Guarantors | Parent and Subsidiaries
Condensed Statement of Income Captions [Line Items]
Total operating revenues									4,205	4,360	4,215
Cost of goods and services sold									2,202	2,583	2,572
Gas distribution revenue | Spectra Energy Partners, LP | Subsidiary Issuer and Guarantor | Parent and Subsidiaries
Condensed Statement of Income Captions [Line Items]
Total operating revenues									0	0	0
Cost of goods and services sold									0	0	0
Gas distribution revenue | Enbridge Energy Partners, L.P. | Subsidiary Issuer and Guarantor | Parent and Subsidiaries
Condensed Statement of Income Captions [Line Items]
Total operating revenues									0	0	0
Cost of goods and services sold									0	0	0
Transportation and other services revenues
Condensed Statement of Income Captions [Line Items]
Total operating revenues									16,555	14,358	13,877
Transportation and other services revenues | Eliminations and Other
Condensed Statement of Income Captions [Line Items]
Total operating revenues									0	0	0
Transportation and other services revenues | Parent Issuer and Guarantor | Parent and Subsidiaries
Condensed Statement of Income Captions [Line Items]
Total operating revenues									0	0	0
Transportation and other services revenues | Subsidiary Non-Guarantors | Parent and Subsidiaries
Condensed Statement of Income Captions [Line Items]
Total operating revenues									16,555	14,358	13,877
Transportation and other services revenues | Spectra Energy Partners, LP | Subsidiary Issuer and Guarantor | Parent and Subsidiaries
Condensed Statement of Income Captions [Line Items]
Total operating revenues									0	0	0
Transportation and other services revenues | Enbridge Energy Partners, L.P. | Subsidiary Issuer and Guarantor | Parent and Subsidiaries
Condensed Statement of Income Captions [Line Items]
Total operating revenues									$ 0	$ 0	$ 0

CONDENSED CONSOLIDATING FINAN_5

CONDENSED CONSOLIDATING FINANCIAL INFORMATION - Condensed Consolidating Statements of Financial Position (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Balance Sheet Statements, Captions [Line Items]
Cash and cash equivalents	$ 648	$ 518
Restricted cash	28	119
Accounts receivable and other	6,781	6,517
Accounts receivable from affiliates	69	79
Short-term loans receivable from affiliates	0	0
Inventory	1,299	1,339
Total Current assets	8,825	8,572
Property, plant and equipment, net	93,723	94,540
Long-term loans receivable from affiliates	0	0
Investments in subsidiaries	0	0
Long-term investments (Note 13)	16,528	16,707
Restricted long-term investments	434	323
Deferred amounts and other assets	7,433	8,558
Intangible assets, net	2,173	2,372
Goodwill	33,153	34,459
Deferred income taxes	1,000	1,374
Total assets	163,269	166,905
Short-term borrowings	898	1,024
Accounts payable and other	10,063	9,836
Accounts payable to affiliates	21	40
Interest payable	624	669
Short-term loans payable to affiliates	0	0
Environmental liabilities		27
Current portion of long-term debt	4,404	3,259
Total Current liabilities	16,010	14,855
Long-term debt	59,661	60,327
Other long-term liabilities	8,324	8,834
Long-term loans payable to affiliates	0	0
Deferred income taxes	9,867	9,454
Total Liabilities	93,862	93,470
Controlling interests	66,043	69,470
Noncontrolling interests	3,364	3,965
Total Equity	69,407	73,435	$ 65,732
Total liabilities and equity	163,269	166,905
Eliminations and Other
Condensed Balance Sheet Statements, Captions [Line Items]
Cash and cash equivalents	0	0
Restricted cash	0	0
Accounts receivable and other	0	0
Accounts receivable from affiliates	(525)	(518)
Short-term loans receivable from affiliates	(10,069)	(8,285)
Inventory	0	0
Total Current assets	(10,594)	(8,803)
Property, plant and equipment, net	0	0
Long-term loans receivable from affiliates	(85,417)	(14,274)
Investments in subsidiaries	(119,374)	(120,181)
Long-term investments (Note 13)	(572)	(3,682)
Restricted long-term investments	0	0
Deferred amounts and other assets	(849)	(1,726)
Intangible assets, net	0	0
Goodwill	0	0
Deferred income taxes	0	328
Total assets	(216,806)	(148,338)
Short-term borrowings	0	0
Accounts payable and other	(476)	(6)
Accounts payable to affiliates	(525)	(518)
Interest payable	0	0
Short-term loans payable to affiliates	(10,069)	(8,285)
Environmental liabilities		0
Current portion of long-term debt	0	0
Total Current liabilities	(11,070)	(8,809)
Long-term debt	0	0
Other long-term liabilities	(849)	(1,726)
Long-term loans payable to affiliates	(85,417)	(14,274)
Deferred income taxes	(4,291)	(4,400)
Total Liabilities	(101,627)	(29,209)
Controlling interests	(118,543)	(123,094)
Noncontrolling interests	3,364	3,965
Total Equity	(115,179)	(119,129)
Total liabilities and equity	(216,806)	(148,338)
Parent Issuer and Guarantor | Parent and Subsidiaries
Condensed Balance Sheet Statements, Captions [Line Items]
Cash and cash equivalents	0	0
Restricted cash	9	9
Accounts receivable and other	429	283
Accounts receivable from affiliates	746	726
Short-term loans receivable from affiliates	1,691	3,943
Inventory	0	0
Total Current assets	2,875	4,961
Property, plant and equipment, net	248	140
Long-term loans receivable from affiliates	47,285	10,318
Investments in subsidiaries	80,456	78,474
Long-term investments (Note 13)	1,701	4,561
Restricted long-term investments	0	0
Deferred amounts and other assets	998	1,700
Intangible assets, net	247	234
Goodwill	0	0
Deferred income taxes	486	817
Total assets	134,296	101,205
Short-term borrowings	0	0
Accounts payable and other	2,765	2,742
Accounts payable to affiliates	736	946
Interest payable	279	283
Short-term loans payable to affiliates	367	426
Environmental liabilities		0
Current portion of long-term debt	2,160	1,853
Total Current liabilities	6,307	6,250
Long-term debt	27,290	22,893
Other long-term liabilities	1,295	2,428
Long-term loans payable to affiliates	33,686	76
Deferred income taxes	0	0
Total Liabilities	68,578	31,647
Controlling interests	65,718	69,558
Noncontrolling interests	0	0
Total Equity	65,718	69,558
Total liabilities and equity	134,296	101,205
Subsidiary Non-Guarantors | Parent and Subsidiaries
Condensed Balance Sheet Statements, Captions [Line Items]
Cash and cash equivalents	611	502
Restricted cash	19	110
Accounts receivable and other	6,340	6,211
Accounts receivable from affiliates	(164)	(142)
Short-term loans receivable from affiliates	4,417	653
Inventory	1,299	1,339
Total Current assets	12,522	8,673
Property, plant and equipment, net	93,475	94,400
Long-term loans receivable from affiliates	35,672	1,344
Investments in subsidiaries	14,782	15,567
Long-term investments (Note 13)	14,467	14,841
Restricted long-term investments	434	323
Deferred amounts and other assets	7,282	8,558
Intangible assets, net	1,926	2,138
Goodwill	33,153	34,459
Deferred income taxes	514	229
Total assets	214,227	180,532
Short-term borrowings	898	1,024
Accounts payable and other	7,745	7,059
Accounts payable to affiliates	(640)	(677)
Interest payable	242	225
Short-term loans payable to affiliates	5,653	7,177
Environmental liabilities		27
Current portion of long-term debt	1,726	723
Total Current liabilities	15,624	15,558
Long-term debt	24,147	23,215
Other long-term liabilities	7,864	8,100
Long-term loans payable to affiliates	48,619	12,696
Deferred income taxes	13,887	13,523
Total Liabilities	110,141	73,092
Controlling interests	104,086	107,440
Noncontrolling interests	0	0
Total Equity	104,086	107,440
Total liabilities and equity	214,227	180,532
Spectra Energy Partners, LP | Subsidiary Issuer and Guarantor | Parent and Subsidiaries
Condensed Balance Sheet Statements, Captions [Line Items]
Cash and cash equivalents	33	16
Restricted cash	0	0
Accounts receivable and other	8	15
Accounts receivable from affiliates	0	0
Short-term loans receivable from affiliates	0	0
Inventory	0	0
Total Current assets	41	31
Property, plant and equipment, net	0	0
Long-term loans receivable from affiliates	73	73
Investments in subsidiaries	18,956	19,777
Long-term investments (Note 13)	932	987
Restricted long-term investments	0	0
Deferred amounts and other assets	1	9
Intangible assets, net	0	0
Goodwill	0	0
Deferred income taxes	0	0
Total assets	20,003	20,877
Short-term borrowings	0	0
Accounts payable and other	28	7
Accounts payable to affiliates	367	233
Interest payable	52	56
Short-term loans payable to affiliates	2,058	682
Environmental liabilities		0
Current portion of long-term debt	518	0
Total Current liabilities	3,023	978
Long-term debt	4,435	7,276
Other long-term liabilities	2	2
Long-term loans payable to affiliates	0	0
Deferred income taxes	271	331
Total Liabilities	7,731	8,587
Controlling interests	12,272	12,290
Noncontrolling interests	0	0
Total Equity	12,272	12,290
Total liabilities and equity	20,003	20,877
Enbridge Energy Partners, L.P. | Subsidiary Issuer and Guarantor | Parent and Subsidiaries
Condensed Balance Sheet Statements, Captions [Line Items]
Cash and cash equivalents	4	0
Restricted cash	0	0
Accounts receivable and other	4	8
Accounts receivable from affiliates	12	13
Short-term loans receivable from affiliates	3,961	3,689
Inventory	0	0
Total Current assets	3,981	3,710
Property, plant and equipment, net	0	0
Long-term loans receivable from affiliates	2,387	2,539
Investments in subsidiaries	5,180	6,363
Long-term investments (Note 13)	0	0
Restricted long-term investments	0	0
Deferred amounts and other assets	1	17
Intangible assets, net	0	0
Goodwill	0	0
Deferred income taxes	0	0
Total assets	11,549	12,629
Short-term borrowings	0	0
Accounts payable and other	1	34
Accounts payable to affiliates	83	56
Interest payable	51	105
Short-term loans payable to affiliates	1,991	0
Environmental liabilities		0
Current portion of long-term debt	0	683
Total Current liabilities	2,126	878
Long-term debt	3,789	6,943
Other long-term liabilities	12	30
Long-term loans payable to affiliates	3,112	1,502
Deferred income taxes	0	0
Total Liabilities	9,039	9,353
Controlling interests	2,510	3,276
Noncontrolling interests	0	0
Total Equity	2,510	3,276
Total liabilities and equity	$ 11,549	$ 12,629

CONDENSED CONSOLIDATING FINAN_6

CONDENSED CONSOLIDATING FINANCIAL INFORMATION - Condensed Consolidating Statements of Cash Flows (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by operating activities	$ 9,398	$ 10,502	$ 6,658
Capital expenditures	(5,492)	(6,806)	(8,287)
Long-term investments and restricted long-term investments	(1,159)	(1,312)	(3,586)
Distributions from equity investments in excess of cumulative earnings	417	1,277	125
Additions to intangible assets	(200)	(540)	(789)
Cash acquired in Merger Transaction	0	0	682
Affiliate loans, net	(314)	(76)	(22)
Proceeds from dispositions	2,110	4,452	628
Contributions to subsidiaries	0	0	0
Return of share capital from subsidiaries	0	0	0
Advances to affiliates	0	0	0
Repayment of advances to affiliates	0	0	0
Other	(20)	(12)	212
Net cash used in investing activities	(4,658)	(3,017)	(11,037)
Net change in short-term borrowings	(127)	(420)	721
Net change in commercial paper and credit facility draws	825	(2,256)	(1,249)
Debenture and term note issues, net of issue costs	6,176	3,537	9,483
Debenture and term note repayments	(4,668)	(4,445)	(5,054)
Purchase of interest in consolidated subsidiary	0	0	(227)
Sale of noncontrolling interest in subsidiary	0	1,289	0
Contributions from noncontrolling interests	12	24	832
Distributions to noncontrolling interests	(254)	(857)	(919)
Contributions from redeemable noncontrolling interests	0	70	1,178
Distributions to redeemable noncontrolling interests	0	(325)	(247)
Contributions from parents	0	0	0
Distributions to parents	0	0	0
Sponsored Vehicle buy-in cash payment	0	(64)	0
Preference shares issued	0	0	489
Redemption of preferred shares	(300)	(210)	0
Common shares issued	18	21	1,549
Preference share dividends	(383)	(364)	(330)
Common share dividends	(5,973)	(3,480)	(2,750)
Advances from affiliates	0	0	0
Repayment of advances from affiliates	0	0	0
Other	(71)	(23)	0
Net cash (used in)/provided by financing activities	(4,745)	(7,503)	3,476
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	44	68	(72)
Net increase/(decrease) in cash and cash equivalents and restricted cash	39	50	(975)
Cash and cash equivalents and restricted cash at beginning of year	637	587	1,562
Cash and cash equivalents and restricted cash at end of year	676	637	587
Eliminations and Other
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by operating activities	(3,834)	(4,389)	(3,276)
Capital expenditures	0	0	0
Long-term investments and restricted long-term investments	0	78	202
Distributions from equity investments in excess of cumulative earnings	(1,196)	(1,269)	(957)
Additions to intangible assets	0	0	0
Cash acquired in Merger Transaction			0
Affiliate loans, net	0		0
Proceeds from dispositions	0	0	(2,217)
Contributions to subsidiaries	4,771	9,878	6,922
Return of share capital from subsidiaries	(5,281)	(3,753)	(3,724)
Advances to affiliates	114,462	14,251	12,094
Repayment of advances to affiliates	(40,301)	(15,573)	(9,522)
Other	0	0	0
Net cash used in investing activities	72,455	3,612	2,798
Net change in short-term borrowings	0	0	0
Net change in commercial paper and credit facility draws	0	0	0
Debenture and term note issues, net of issue costs	0	0	0
Debenture and term note repayments	0	0	0
Purchase of interest in consolidated subsidiary			2,217
Sale of noncontrolling interest in subsidiary		1,289
Contributions from noncontrolling interests	12	24	832
Distributions to noncontrolling interests	(254)	(857)	(919)
Contributions from redeemable noncontrolling interests	0	70	615
Distributions to redeemable noncontrolling interests	0	(325)	(247)
Contributions from parents	(4,771)	(9,230)	(6,922)
Distributions to parents	10,553	9,132	8,869
Sponsored Vehicle buy-in cash payment		0
Preference shares issued			0
Redemption of preferred shares	0	0	0
Common shares issued	0	(648)	(1,873)
Preference share dividends	0	0	478
Common share dividends	0	0	0
Advances from affiliates	(114,462)	(14,251)	(12,094)
Repayment of advances from affiliates	40,301	15,573	9,522
Other	0	0
Net cash (used in)/provided by financing activities	(68,621)	777	478
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	0	0	0
Net increase/(decrease) in cash and cash equivalents and restricted cash	0	0	0
Cash and cash equivalents and restricted cash at beginning of year	0	0	0
Cash and cash equivalents and restricted cash at end of year	0	0	0
Parent Issuer and Guarantor | Parent and Subsidiaries
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by operating activities	2,246	1,696	620
Capital expenditures	(75)	(28)	(21)
Long-term investments and restricted long-term investments	(26)	(81)	(202)
Distributions from equity investments in excess of cumulative earnings	0	287	36
Additions to intangible assets	(68)	(43)	(47)
Cash acquired in Merger Transaction			0
Affiliate loans, net	0		0
Proceeds from dispositions	0	1,790	0
Contributions to subsidiaries	(4,759)	(8,131)	(4,866)
Return of share capital from subsidiaries	5,281	3,753	2,192
Advances to affiliates	(50,897)	(6,863)	(7,145)
Repayment of advances to affiliates	15,808	9,427	4,506
Other	0	0	0
Net cash used in investing activities	(34,736)	111	(5,547)
Net change in short-term borrowings	0	0	0
Net change in commercial paper and credit facility draws	3,158	(734)	(1,845)
Debenture and term note issues, net of issue costs	3,621	2,554	8,177
Debenture and term note repayments	(1,450)	0	(1,711)
Purchase of interest in consolidated subsidiary			0
Sale of noncontrolling interest in subsidiary		0
Contributions from noncontrolling interests	0	0	0
Distributions to noncontrolling interests	0	0	0
Contributions from redeemable noncontrolling interests	0	0	563
Distributions to redeemable noncontrolling interests	0	0	0
Contributions from parents	0	0	0
Distributions to parents	0	0	0
Sponsored Vehicle buy-in cash payment		(64)
Preference shares issued			489
Redemption of preferred shares	0	0	0
Common shares issued	18	21	1,549
Preference share dividends	(383)	(364)	(330)
Common share dividends	(5,973)	(3,480)	(2,336)
Advances from affiliates	46,860	710	407
Repayment of advances from affiliates	(13,361)	(443)	(40)
Other	0	0
Net cash (used in)/provided by financing activities	32,490	(1,800)	4,923
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	0	0	0
Net increase/(decrease) in cash and cash equivalents and restricted cash	0	7	(4)
Cash and cash equivalents and restricted cash at beginning of year	9	2	6
Cash and cash equivalents and restricted cash at end of year	9	9	2
Subsidiary Non-Guarantors | Parent and Subsidiaries
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by operating activities	9,675	11,683	9,654
Capital expenditures	(5,417)	(6,778)	(8,266)
Long-term investments and restricted long-term investments	(1,122)	(1,297)	(3,535)
Distributions from equity investments in excess of cumulative earnings	393	1,232	103
Additions to intangible assets	(132)	(497)	(742)
Cash acquired in Merger Transaction			682
Affiliate loans, net	(314)	(76)	(22)
Proceeds from dispositions	2,110	2,662	1,103
Contributions to subsidiaries	0	(1,655)	0
Return of share capital from subsidiaries	0	0	0
Advances to affiliates	(60,787)	(5,685)	(3,020)
Repayment of advances to affiliates	22,136	4,124	2,887
Other	(20)	(12)	212
Net cash used in investing activities	(43,153)	(7,982)	(10,598)
Net change in short-term borrowings	(127)	(420)	721
Net change in commercial paper and credit facility draws	695	449	(1,053)
Debenture and term note issues, net of issue costs	2,555	983	787
Debenture and term note repayments	(704)	(3,288)	(2,810)
Purchase of interest in consolidated subsidiary			(1,969)
Sale of noncontrolling interest in subsidiary		0
Contributions from noncontrolling interests	0	0	0
Distributions to noncontrolling interests	0	0	0
Contributions from redeemable noncontrolling interests	0	0	0
Distributions to redeemable noncontrolling interests	0	0	0
Contributions from parents	4,771	8,223	6,922
Distributions to parents	(8,888)	(6,564)	(6,093)
Sponsored Vehicle buy-in cash payment		0
Preference shares issued			0
Redemption of preferred shares	(300)	(210)	1,613
Common shares issued	0	0	0
Preference share dividends	0	0	0
Common share dividends	0	0	(414)
Advances from affiliates	53,675	8,566	9,074
Repayment of advances from affiliates	(18,165)	(11,449)	(6,635)
Other	(60)	(18)
Net cash (used in)/provided by financing activities	33,452	(3,728)	143
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	44	68	(70)
Net increase/(decrease) in cash and cash equivalents and restricted cash	18	41	(871)
Cash and cash equivalents and restricted cash at beginning of year	612	571	1,442
Cash and cash equivalents and restricted cash at end of year	630	612	571
Spectra Energy Partners, LP | Subsidiary Issuer and Guarantor | Parent and Subsidiaries
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by operating activities	1,676	1,751	355
Capital expenditures	0	0	0
Long-term investments and restricted long-term investments	(11)	(12)	(51)
Distributions from equity investments in excess of cumulative earnings	24	45	22
Additions to intangible assets	0	0	0
Cash acquired in Merger Transaction			0
Affiliate loans, net	0		0
Proceeds from dispositions	0	0	0
Contributions to subsidiaries	0	(79)	0
Return of share capital from subsidiaries	0	0	0
Advances to affiliates	0	0	(519)
Repayment of advances to affiliates	0	518	0
Other	0	0	0
Net cash used in investing activities	13	472	(548)
Net change in short-term borrowings	0	0	0
Net change in commercial paper and credit facility draws	(2,011)	(962)	1,965
Debenture and term note issues, net of issue costs	0	0	519
Debenture and term note repayments	0	(648)	(533)
Purchase of interest in consolidated subsidiary			0
Sale of noncontrolling interest in subsidiary		0
Contributions from noncontrolling interests	0	0	0
Distributions to noncontrolling interests	0	0	0
Contributions from redeemable noncontrolling interests	0	0	0
Distributions to redeemable noncontrolling interests	0	0	0
Contributions from parents	0	0	0
Distributions to parents	(1,014)	(1,902)	(1,987)
Sponsored Vehicle buy-in cash payment		0
Preference shares issued			0
Redemption of preferred shares	0	0	0
Common shares issued	0	648	227
Preference share dividends	0	0	0
Common share dividends	0	0	0
Advances from affiliates	5,678	1,474	0
Repayment of advances from affiliates	(4,321)	(826)	0
Other	(4)	(5)
Net cash (used in)/provided by financing activities	(1,672)	(2,221)	191
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	0	0	0
Net increase/(decrease) in cash and cash equivalents and restricted cash	17	2	(2)
Cash and cash equivalents and restricted cash at beginning of year	16	14	16
Cash and cash equivalents and restricted cash at end of year	33	16	14
Enbridge Energy Partners, L.P. | Subsidiary Issuer and Guarantor | Parent and Subsidiaries
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by operating activities	(365)	(239)	(695)
Capital expenditures	0	0	0
Long-term investments and restricted long-term investments	0	0	0
Distributions from equity investments in excess of cumulative earnings	1,196	982	921
Additions to intangible assets	0	0	0
Cash acquired in Merger Transaction			0
Affiliate loans, net	0		0
Proceeds from dispositions	0	0	1,742
Contributions to subsidiaries	(12)	(13)	(2,056)
Return of share capital from subsidiaries	0	0	1,532
Advances to affiliates	(2,778)	(1,703)	(1,410)
Repayment of advances to affiliates	2,357	1,504	2,129
Other	0	0	0
Net cash used in investing activities	763	770	2,858
Net change in short-term borrowings	0	0	0
Net change in commercial paper and credit facility draws	(1,017)	(1,009)	(316)
Debenture and term note issues, net of issue costs	0	0	0
Debenture and term note repayments	(2,514)	(509)	0
Purchase of interest in consolidated subsidiary			(475)
Sale of noncontrolling interest in subsidiary		0
Contributions from noncontrolling interests	0	0	0
Distributions to noncontrolling interests	0	0	0
Contributions from redeemable noncontrolling interests	0	0	0
Distributions to redeemable noncontrolling interests	0	0	0
Contributions from parents	0	1,007	0
Distributions to parents	(651)	(666)	(789)
Sponsored Vehicle buy-in cash payment		0
Preference shares issued			0
Redemption of preferred shares	0	0	(1,613)
Common shares issued	0	0	1,646
Preference share dividends	0	0	(478)
Common share dividends	0	0	0
Advances from affiliates	8,249	3,501	2,613
Repayment of advances from affiliates	(4,454)	(2,855)	(2,847)
Other	(7)	0
Net cash (used in)/provided by financing activities	(394)	(531)	(2,259)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	0	0	(2)
Net increase/(decrease) in cash and cash equivalents and restricted cash	4	0	(98)
Cash and cash equivalents and restricted cash at beginning of year	0	0	98
Cash and cash equivalents and restricted cash at end of year	$ 4	$ 0	$ 0

QUARTERLY FINANCIAL DATA (UNA_3

QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) - CAD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Total operating revenues	$ 12,352	$ 11,598	$ 13,263	$ 12,856	$ 11,562	$ 11,345	$ 10,745	$ 12,726	$ 50,069	$ 46,378	$ 44,378
Operating income	1,768	1,588	2,285	2,619	1,513	854	1,571	878	8,260	4,816	1,571
Earnings	914	1,060	1,830	2,023	1,283	213	1,327	510	5,827	3,333	3,266
Earnings attributable to controlling interests	842	1,045	1,832	1,986	1,184	4	1,160	534	5,705	2,882	2,859
Earnings/(loss) attributable to common shareholders	$ 746	$ 949	$ 1,736	$ 1,891	$ 1,089	$ (90)	$ 1,071	$ 445	$ 5,322	$ 2,515	$ 2,529
Earnings per common share
Earnings per common share attributable to common shareholders (in CAD per share)	$ 0.37	$ 0.47	$ 0.86	$ 0.94	$ 0.60	$ (0.05)	$ 0.63	$ 0.26	$ 2.64	$ 1.46	$ 1.66
Diluted earnings per common share attributable to common shareholders (in CAD per share)	$ 0.36	$ 0.47	$ 0.86	$ 0.94	$ 0.60	$ (0.05)	$ 0.63	$ 0.26	$ 2.63	$ 1.46	$ 1.65